Offshore oil and gas development southern California : a staff report

[From the U.S. Government Printing Office, www.gpo.gov]

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OCS PROJECT TASK FORCE/OFFICE OF PLANNING AND RESEARCH

VOLUME ONE

OFFSHORE
OIL AND GAS:
DEVELOPMENT:
SOUTHERN'.
..:CALIFORNIA

OFFICE OF PLANNING AND RESEARCH
Bill Press, Director Michael L. Fischer, Deputy Director

OCS PROJECT TASK FORCE
David CaZfee, William DeZZer_, Richard Grix,.Richard Hammond (Project Director),,
AZZan Lind, Trevor O'NeiZl, Carol PiZZsbury., Suzanne Reed (Project Manager)

SUPPORT STAFF:
Nancy Aurich (Administrative Assistant), Cassie George, Joanne HaraZson, Tad
Hubbard, Carolyn Lentz, Loni Mahan, Lois Naylor, Randy Petersen., Tom TesZuk.,
Mike Yeager

CARTOGRAPHIC STAFF:
Corinne Brainard, Marlin DuZay., David Howerton, April Thanos

EDITORS
CZaudid-Buckner, Kay Munro@
e, R. B. Read

PROJECT CONSULTANTS
George Taylor, Environmental Research Technology, Inc.
Public Interest Economics-West, Robert Wolcott, Director
State Lands Division,.WiZZiam Northrop, Executive Officer
Ruthann Corwin and Patrick Heffernan

PHOTOGRAPHY
Pages 409 and-434, courtesy of Clean Seas., Inc.@ pages 521 and 563, courtesy of
Exxon Company, USA; all others by OPR staff.

Copies of Offshore Oil and Gas Development: Southern California
VoZumns Z and 2 may be purchased from: General Services,
Publications Section, P.O. Box ZOZ5_, North Highlands, 95660,
(9161445-ZO20). $2.ZO per set, includes: postage, handling,
and sales tax.

This report was prepared with financial assistance from the Office of
Coastal Zone Management, National Oceanic and Atmospheric Administration,
under provisions of the Federal Coastal Zone Management Act of 19.72.

OFFSHORE
OIL AND GAS
DEVELOPMENT:
SOUTHERN
CALIFORNIA

VOLUME ONE
U.S. DEPARTMENT OF COMMERCE NOAA
COASTAL SERVICES CENTER
2234 SOUTH HOBSON AVENUE
A-Staff Report CHARLESTON, SC 29405-2413

Prepared for the California Coastal Commission
by the OCS Project Task Force,
Office of Planning and Research

October 1977

Office of Planning and Research
1400 Tenth Street
Sacramento, California 95814
(916) 322-2318

Property of CSC Library

S'
tate of Tatiforittia

GOVERNOR'S OFFICE
OFFICE OF PLANNING AND RESEARCH
1400 TENTH STREET

SACRAMENTO 95814

EDMUND G. BROWN JR.
GOVERNOR

Mr. Bradford Lundborg, Chairman
California Coastal Zone Conservation Commissions
1540 Market Street, Second Floor
San Francisco, California 94102

Dear Mr. Lundborg:

In fulfillment of a contract between this office and the California Coastal
Commission, I hereby transmit this report on the implications of OCS
development for southern California.

.'I believe this document more than satisfies the objectives your Commission
established for it, and that it will serve well the long-term needs of the
Commission and the State with regard to management of our OCS resources.
I also believe that the report wi.11 prove itself of immediate value to the
Commission in its work on local coastal programs, the Coastal Energy Impact
Program, federal approval of the Cal'ifornia Coastal Management Program, and
coastal energy facilities permit decisions.

To obtain the widest range of viewpoints on the issues covered in this
report, OPR 'made a major effort to involve all parties concerned with OCS
matters. Over 600 individuals representing themselves, interest groups,
petroleum companies, and State and local government agencies were given the
opportunity to review each chapter in draft form. Twenty workshops were
held on the report in the five southern coastal counties. Several working
sessions were devoted to discussin@g key issues with selected scientists and
engineers. Through numerous interviews and extensive questionnaires, OPR's
OCS Task Force collected specific data on crucial aspects of current and
projected OCS activities. The Task Force also met with major southern
California OCS operators to discuss candidly both the industry's philosoph-
ical concerns with government intervention in OCS development and its prac-
tical, concerns over implementing specific development proposals.

The problems dealt with in this report are complex, and their resolution
will require an unprecedented level of cooperation between public and
private institutions. The study, therefore, makes recommendations to all
levels of government, to the petroleum industry at large, and to the pro-
ponents of specific developments that are or soon will be affecting the
coast of southern California. We ask all interested parties to consider
these recommendations carefully and to act on them to the fullest extent
possible.

Mr. Bradford Lundborg

A major finding of the study is that this State's primary responsibility
for overseeing OCS development should lie with the California Coastal
Commission. Therefore, I urge members of the Commission, in their de-
tailed consideration of all the findings and recommendations, to support
the recommendations made to others, and to pay particular attention to
those recommendations which express the Commission's goals and objectives
for OCS-related oil and gas development.

The Office of Planning and Research is ready to answer-any questions that
you may have about the study, to meet with your staff to discuss the in-
tricate details of pending OCS development proposals, and to present our
major findings and recommendations to the Commission at your earliest
convenience.

Since y,

Bill ress
Director
n 4ce
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Photo opposite: Platform Hondo, located on
the Santa Ynez Unit, Exxon Company, USA.

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ACKNOWLEDGEM.ENTS

During the course of the study, many individuals and orqa-
nizations freely contributed their advice and opinions on its
direction and substance. Thouqh not all will ag_ree with
the way some tooics-have been handled, we wish to express our
appreciation to them and the agencies they represent for their
.concerted.effort.

From the petroleum industry, we wish to thank Jack I-11undley,
Atlantic Richfield; Tom Hudson and Forrest Smith, Chevron Company,
USA; Captain A. J. Bush, Clean Coastal Waters, Inc.; Darrell 1.4arner,
Exxon Company, USA; Richard Voils, Mobil Oil Corporation; Ben Piester,
Phi 11 i ps Petrol eum; and, Hank Wri qh.t, Western 0-11 and Gas Associ ati on.

.Representatives of the federal qovernment we wish to thank
include Bill Grant, Mike Carter, Tom Cooke, and Don Keene of the
Bureau of Land Management; Lawrence McBride, Al Powers, and Peter
Tweedt of the Department of the Interior; Dr. Jerry Gault of@the
National Oceanic and Atmospheric Administration; Lt. Richard Bran@es,
U.S. Coast Guard; and, Maur'v Adams, Henry Cullen, Bill La Velle,
Hillary Oden, and Michael Reitz of the U.S. Geological Survey.
'From state agencies, we wish to thank Paul Allen, Andy Ran @/i eri
and Pete Venturini, Air Resources Board; Rob Solomon, Energy Commis-
sion; Walt Putman and Robert Bell, De 'partment of Fish and Game; Glenn
Ledingham, Division of Oil and Gas; Dr. James Rote, Resources Agencv-,
P,on Everitts, John Messer, Bob Paul, Dwight Sanders,. Moose Thompson,
and Dr. Ed Welday of the State Lands Division; and John'White-, Assem-
bly Committee, Resources, Land Use and Energy.

Representatives of local governments we wish to thank include
Dennis Allen, City of Long Beach; Steve Sachs and Art Letter, San
Diego County CPO; Al Reynolds and Al McCurdy, Santa Barbara County
OEQ; Graham Smith, City of Los Angeles Mayor's Offi-ce; Joe Chesler,
Los Angeles County DOB; and Cob Davis, Huntington Beach.

'Others we wish to thank include Jeff Frautschy, Joseph
-Reed, and Dr. Richard Schwart@zlose, Scripps Institution-of
Oceanography; Dr. Ronald Kolpack, University of Southern
California;'and Dr. George Hampson, Woods Hole Oceanographic
Institute.

Consultants who prepared major analyses for this report
included.George-Taylor, Environmental Research'and Technology,
Inc., Santa Barbara; Sandra Baron:, Mike Kavanaugh, Dr. Richard
Norgaard, and Rob Wolcott, Public Interest Economics West (PIE
West), San Francisco; and Ruthann Corviin and Patrick-Heffernan,
Santa Barbara. George Taylor is the author of "Air Quality
Impacts of Outer Continental Shelf Development in the Santa
Barbara Channel" which.appears as the second part of Chapter 15.
-The PIE West consultants are the authors of Chapter 18, "Economic
Ef-.-ects: Benefits vs. Burdens" and of "The Santa Ynez Petroleum

Transportation Controversy" which appears as a part of Appendix 5.
Ruthann Corwin and Patrick Heffernan are the authors of "Local
Government and Offshore Oil: Santa-Barbara Case Study" (unpub-
lished). Staff of the State Lands Division prepared Appendix 1
of this report.,

Support staff involved in the preparation of this report -
include Nancy Aurich (Project Administration Assistant), Cassie
George, Joanne Haralson, Tad Hubbard, Carolyn Lentz, Loni Mahan.,
Lois Naylor, Randy Petersen, Tom Tesluk, and Mike Yeager. Carto-
graphic work was prepared by Corinne Brainard, Marlin Dulay,
David Howerton, and April Th-anos.. Professional staff who also
contributed to the project include Bill Armstead, Claudia Ayers,
Joe Wharton, and Woody Wilson.-

The final report was designed and readied for publication
by Allan Lind. It was edited by Claudia Buckner, Kay Munroe,
and R. B. Read. The figures and maps were designed and executed
under the direction of Marlin Dulay.

OCS Project Task Force: David Calfee, William Deller,
Richard Grix, Rich-ard ff-a-mmond (Project Director), Allan Lind,
Trevor O'Neill, Carol Pillsbury, and Suzanne Reed (Project
Manager).

TABLE OF CONTENTS
VOLUME ONE
LETTER OF TRANSMITTAL . . ... . . . . . . . . . . . . . . V

ACKNOWLEDGEMENTS . . . . . . . . . . . . . . . . . . . . Ix

P A R T 0 N E INTRODUCTION AND SUMMARY . . . . . . . . . 1

CHAPTER 1: INTRODUCTION . . . . . . . . . . .. . . . . . 3

@Perspective

CHAPTER 2: SUMMARY . . . . . . . . . .. . . . ... . . . . 7

Management of OCS DeveZopment_, Adequacy of
Decision Informationj - Air Quality, Sensitive
Coastal Resourc 'es, Oil Spills, Economic
Effects., Facilities Planning, Transportation,
Development Scenarios, Lease.SaZe #48

P A R T T W 0 FINDINGS AND RECOMMENDATIONS . . . . . . . 13

CHAPTER 3: MANAGEMENT OF OCS DEVELOPMENT . . . ... . . . 15.

CHAPTER 4: ADEQUACY OF DECISION INFORMATION . . . . . . 27

CHAPTER 5: AIR QUALITY . . . . . . . . . . . . . . . . .. 39

CHAPTER 6: SENSITIVE COASTAL RESOURCES . . . . . . . . . 45

CHAPTER 7: OIL SPILLS . . . I. . . . . . . . . . . . . . 51

CHAPTER 8: ECONOMIC EFFECTS OF LEASE SALE #35 . . . . .61

CHAPTER 9: FACILITIES PLANNING . . . . . . . . . . . . . 65

CHAPTER 10: TRANSPORTATION . . .. . . . . . . . . . . . . 75

CHAPTER 11: DEVELOPMENT SCENARIOS . . . . . . . . . . . 85

CHAPTER 12: OCS LEASE SALE #48 . . . . . . . . . . . . 107

P A R T T H R E E : BACKGROUND REPORTS . . ... . . . . . 111

CHAPTER 13: OCS MANAGEMENT: THE PLAYERS
AND THE RULES . . . .. . . . . . . . . . . 113

Understanding the Federal Leasing and
Management Process; State and Local
Controls; Bridging the Gap: CZMA

CHAPTER 14: THE RESOURCE BASE: EDUCATED GUESSES . . . 167

Occurrence of Petroleum., History of
California Offshore Production, Present
Status, Prospects

CHAPTER 15: AIR QUALITY: OMISSIONS AND EMISSIONS. .189

Part One: Air Quality Regulations and -
Research Priorities . . . . . . . . .. 191

Air Quality Regulations, OCS Air Quality
Impact Assessment and Research Priorities

Part Two: Air Quality Impacts of Outer
Continental Shelf Development
in the Santa Barbara Channel . . . . . 220

Summary, Comments on Previous Air Quality
Impact Analyses for Santa Barbara and
Vicinity, Environmental Setting., ARTSIM
Baseline Runs., ARTSIM OCS'Impact Simulation.
Runs, Air Quality Inpacts of Other Pollutants,
Conclusions, Appendix A, Appendix B, Appendix C

Glossary of Air Pollution Terms . . . . . .301

CHAPTER 16: SENSITIVE RESOURCES: INVALUABLE
VALUES . . . . . . . . . . . . . . . . . 307

Critical Habitats, Economic and Recreational
Resources, Officially' Designated Unique
Biological Environments

CHAPTER 17: OIL SPILL: PREDICTING THE
UNPREDICTABLE . . . . . . . . . . . . . . 387

Sources of Oil in Ocean Waters, Fate of
Spilled Oil in the Marine Environment, Oil
SpiZZ Trajectories, The Effects of a SpiZZ,
Legal Aspects, Oil SpiZZ Response

CHAPTER 18: ECONOMIC EFFECTS: BENEFITS VS.
BURDENS . . . . . . . . . . . . . . . . . 453

Introduction, Scenario Development, ConcZusion,
Appendix A, Appendix B, Appendix C

CHAPTER 19-: FACILITIES PLANNING: EASING THE
ONSHORE/OFFSHORE BIND . . . . . . . . . . 497

Area Planning, Unitization, Coordinating
Onshore Development, Appendix A, Appendix B

CHAPTER 20: TRANSPORTATION: CROSSING THE WATERS .551

Transportation Requirements of Offshore
Crude Oil and Natural Gas; Pipelines and
PipeZaying; Marine Transport; Environmental
Risks: Tankers vs. Pipelines-- Externalities:
Alaska, Elk Hills, and Indonesia

Xii

CHAPTER 21: DEVELOPMENT.SCENARIOS: WORKS IN
PROGRESS . . . . . . . . . . . . . . . . . 577

'Summary, The Scenarios

CHAPTER 22: LEASE SALE #48: BEGINNING AGAIN . . . . . 613

Background, ConcLusion
VOLUME TWO
P A R T F 0 U R APPENDICES . . . . . . . . . . . . . . 625

APPENDIX 1: OIL AND GAS DEVELOPMENT: SANTA
BARBARA CHANNEL - SOUTHERN CALIFORNIA
OCS . . . . . . . . . . . . . . . . . . . 627

APPENDIX 2: PRODUCTION SCENARIOS . . . . . . . . . . . 663

APPENDIX 3: EXISTING PETROLEUM AND GAS-RELATED
FACILITIES . . . . . . . . . . . . . . . . 691

APPENDIX 4: PROFILES ON OCS OPERATORS 755

APPENDIX 5: SANTA YNEZ CONTROVERSY . . . . . . . . . .. 781'

APPENDIX 6: WORKSHOP PARTICIPANTS . . . . . . . . . . 813

APPENDIX 7: DEPARTMENT OF FISH AND GAME: OIL
SPILLS WORKSHOPS . . . . . . . . . . . . . 817

APPENDIX 8: RESPONSE TO COMMENTS ON FINDINGS
AND RECOMMENDATIONS . . . . . .. . . . . . 821

GLOSSARY AND ABBREVIATIONS . . . . . . . . . . . . . . 871

Front cover: Sun Production Company's
Platform Hillhouse on the Dos Cuadras Offshore.field.

Back cover: The Dos Cuadras Offshore field, from left to right:
@Sun's Platform Hillhouse and Union's Platforms "A," "B," and "C."

Photo opposite: Platform Holly on the South
Elwood Offshore field, Atlantic Richfield Company.

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STUDY AREA

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CHAPTER 1:

INTRODUCTION

In late 1975, the California Office of Planning and Research
prepared an initial study of effects of Lease Sale #35, Onshore
Impact of Offshore Southern California Lease Sale No. 35. That
study also identified critical gaps i.n federal impact assessments
of southern California oil and gas development. Specifically, the
study found that:

o Interior Department estimates of-OCS resources were not
made available in a form useful to state and local planners;

o the data necessary for the state to make an independent
evaluation were withheld;

o the localized onshore consequences of new or expanded
onshore facilities related to offshore oil and gas develop-
ment were not identified;-

o the impacts on air quality of offshore petroleum production,
transportation, storage,.processing, and distribution were
ignored; and,

o the-relationship of OCS development,to California's.coastal
management program was inadequately discussed.

Building upon the information collected for the earlier study,
this report, Offshore Oil'and Gas Development: Southern California,
describes in greater detail the spe.cific effects of OCS development
in southern California. The report examines localized adverse effects
of OCS development and recommends changes- in existing federal, state,
and local institutional arrangements to lessen or eliminate these
effects. The report also examines.the potential for development
and recommends means to achieve the most po'sitive effects from OCS
development. Finally, this report-makes. recommendations concerning
the currently pending southern California.OCS Lease Sale #48.

2-76658 3

PERSPECTIVE

The southern California coastal and offshore areas are richly
.endowed with unique and irreplaceable natural resources. The warm
ocean waters, islands, and.coastal habitats support a-diversity of
marine mammals, fish, shellfish, and other marine organisms, as well
as terrestrial plants, animals, and birds. Many species are rare
and endangered. A number of southern California's industries depend
on coastal and offshore resources, particularly commercial and
sportfishing, tourism, and agriculture. In addition, by virtue of
its underlying geology, this area is also one of the more attractive
regions in the United States for oil and gas development.
Onshore production of oil and gas in southern California
contributes significantly to California's present rank as the
third largest petroleum-producing state in the U.S. Although the
extent of the offshore petroleum resource remains to be determined,
the petroleum industry and federal government rank 'southern Cali-
fornia's OCS potential as extremely high. Offshore petroleum
activities, however, threaten the recreational assets of the coast,
the agricultural base, the unique characteristics of intertidal
zones, offshore shallow banks and islands, and the quality of the
air. Californians desire the preservation of these environmental
resources, and are concerned that once our petroleum resources are
.depleted, we may also find that our air and waters have been
irretrievably polluted and vulnerable habitats have been lost as
well.

0 F F S H 0 R E 0 1 L A N D G A S D E V E L 0 P M E N T
1 8 9 6 T 0 1 9 7 6

Offshore development of oil and gas resources dates back to
1896 when the very first offsh'ore production in the `United States
began in the tidelands of Santa Barbara County. The first state
leases were sold in the 1950s. Today there are approximately 33
.state oil and gas leases in the Santa Barbara Channel tidelands
and another 19 off the Los Angeles and Orange County coasts.
Production of oil and gas from these tideland leases is declining;
'and, with few exceptions, most of these will be exhausted in the
.next decade. Nevertheless, with renewed and accelerated federal
leasing activity, southern California's period of greatest offshore
development and production activity is just beginning.

In 1963, development of the federal OCS lands offshore of
California began with issuance Of 57 leases located in six differ-
ent areas between Point Conception and the Oregon border. Lessees
drilled a total of 21 exploratory wells on these leases between
1963 and 1967. All of these wells were later abandoned as unpro-
ductive and the leases quitclaimed.

In 1966, the Department of the Interior held a one-tract
drainage sale in the Santa Barbara Channel to allow development
.of a known field which was being drained from an adjacent state
,lease. Two years later, California experienced its first major
lease sale concentrated in one area: the Santa Barbara Channel.

As a result of the 1966 and 1968 lease sales, 72 federal leases were
sold in the Channel OCS, of which 65 remain active today. Following
the 1969 blowout at Union Oil Platform "A" in the Dos Cuadras field,
then Secretary of Interior Hickle imposed a temporary moratorium on
development of leases in the Santa Barbara Channel. Until 1976,
only one Santa Barbara Channel operator, Exxon, submitted a develop-
ment plan (Santa Ynez Unit) to the Department for approval. Thus,
the Channel is still in a relatively early stage of development.

In December 1975, the Department of the Interior held southern
Ca lifornia OCS Lease Sale #35. The Department offered approximately
217 tracts for sale, but only 56 were actually leased. Thus far,
Sale #35 lessees have drilled 21 exploratory wells. Exploratory
activities are greatest in the San Pedro Bay area where 17 wells
have been drilled. Shell Oil Company has already identified a com-
mercial discovery on its San Pedro Bay leases and has announced plans
to develop this prospect. The first crude oil or gas production
from Lease Sale #35 tracts should occur soon after 1979.

P R 0 S P E C T S F 0 R T H E F U T U R E

California now faces two additional lease sales. In 1979, the
Department of the Interior proposes to offer tracts in the Southern
California Borderland and Santa Barbara Channel (Lease Sale #48).
In 1981, current Department plans call for offering tracts along
the central and northern California coastline (Lease Sale #53). The
Department is now preparing an environmental impact statement on
Lease Sale #48 and has initiated environmental baseline studies for
the Lease Sale #53 area.

As a result of the Interior Department's removal of federal
obstacles to development in the-Santa Barbara Channel in 1976 and
Lease Sale #35 in 1975, southern California has entered a new era
of offshore oil and gas development. State and federal lessees in
both areas are -actively pursuing exploration and development off
the southern California coast. Future lease sales now contemplated
for this area will sustain, if not increase, this activity through
the next decade. Given the history of OCS development, it is not
unreasonable to assume that some conflicts between OCS activities,
coastal management, and environmental protection goals will occur as
the pace of development accelerates offshore.

Recent changes in federal policy suggest, however, that future
OCS leasing and management decisions will include greater partici-
pation by the affected state and local governments and will eliminate
many potential conflicts. Further, in a letter to Governor Brown
dated June 28, 1977, Secretary of the Interior Cecil Andrus stated,
"This Administration seeks to cooperate with the states because of
our confidence that the states will, when treated as partners, work
in the national interest, as well as their own, in developing off-
shore reserves while protecting the environment." This change in
attitude from previous Administrations', coupled with new planning
tools created by the federal Coastal Zone Management Act Amendments
of 1976, the California Coastal Act of 1976, and changes in federal
OCS leasing and management legislation expected to become law this

year, lay a promising foundation for local/state/federal cooperation
on OCS issues.

Clearly, unfounded or unreasonable regional objections should
not override the national need to increase domestic energy supplies;
but there is also a national and a regional need to minimize air
pollution, damage from oil spills, and damage to wildlife from OCS-
related activities. It is imperative that we both develop OCS energy
resources and protect the environment. This report strikes that
balance.

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Photo above: Platforms Hogan (Phillips), Hope and Heidi (Chevron)
on the Carpinteria Offshore field.

CHAPTER -2:

SUMMARY

Exploration and development in the Santa Barbara Channel
is accelerating after completion of the Santa Barbara Channel
EIS in 1976 and settlement of law suits stemming from the mora-
torium imposed after the 1969 blowout. Lease Sale #35 in
December, 1975, opened an additional 56 tracts in the Southern
California Borderlands to oil and gas development. Two lease
sales formerly scheduled in 1978 for the California OCS have
been delayed. Lease Sale #48 and #53, originally scheduled for
March and October of 1978, respectively, have now been included
in the new OCS leasing schedule covering the period 1979 through
1981. The Department of the Interior will hold Lease Sale #48
in 1979 and Lease Sale #53 in 1981.

The study area encompasses the outer continental shelf
extending offshore from Point Conception in Santa Barbara
County south to the international boundary with Mexico as well
as inland areas to the extent that they are directly affected
by OCS development. Topics covered by the report include insti-
tutional arrangements for manag-ing the OCS, socio-economic and
environmental effects of OCS development, facility siting, and
future leasing. The report suggests changes in the present
system of OCS management and also identifies opportunities for
new OCS development. Recommendations are addressed to federal,
state, and local governments and industry to carry out needed
actions. The major policy and specific development proposals
recommended in this report are summarized in the following
paragraphs.

MANAGEMENT OF O.CS DEVELOPMENT
California has little control over OCS development on
federal offshore lands, but must live with the onshore.economic,
social, and en vironmental consequences of that development.

Federal OCS lands are leased on the basis of speculative esti-
mates of oil and gas potential, without any direct information
from exploratory drilling. Restructuring the federal OCS
leasing process to permit pre-lease exploratory drilling and
to separate exploration and development would provide an
opportunity to decide whether a lease should be developed
after weighing environmental risks against the value of the
producible reserves. Administrative actions by the Interior
Department could make state and local participation in the
present process easier and more effective.

Congress should pass legislation requiring the Secretary of
the Interior to accept the recommendations of an affected state's
governor on proposed OCS action unless the Secretary determines
they are not consistent with the overriding national interest.
The Interior Department should acquire direct information from
on-structure exploratory drilling to make tract-by-tract oil
and gas resource estimates before tracts are offered for sale.
Congress should amend the OCS Lands Act to (1) give the Secre-
tary of the Interior authority to cancel any lease or permit
if continued activity under that lease or permit would cause
serious harm or damage to the surrounding environment,
(2) shorten the primary lease term of OCS leases from five to
three years to encourage early exploration, and (3) remove the
limits on the Secretary of Interior's authority to apply new
or revised regulations to leases maintained under the Act.
The Interior Department should make possible more effective
state and local government participation in the leasing and
management process by involving them in the preparation of
environmental impact statements (EISs) and in informal discus-
sions with offshore operators on development plans. It should
also provide copies of resource reports to the state at.the
same time they are issued to federal agencies and hold an
environmental briefing for state and local representatives on
the lease area before nominations are due.

ADEQUACY OF DECISION INFORMATION

There are three kinds of information state and local govern-
ments need most: oil and gas resource estimates, development
plans, and environmental baseline studies. Oil and gas resource
information, the basic building block for state and local plan-
ning efforts, is held closely by the industry and is not published
in a useful or regular manner by the Interior Department. Offshore
development plans, submitted to the Interior Department by OCS
lessees, could be a valuable planning tool, if they included basic
environmental and economic data in a form useable by state and
local governments, but current law does not require lessees to
make this information available. At the federal level, leasing
decisions are proceeding without the benefit of environmental
baseline information that would allow the formulation of appro-
priate trade-offs between development and environmental protection.

This section includes 17 recommendations for improving
federal, state, and local decision-making information. We
recommend that the Interior Department publish regularly updated
resource estimates and.provide California with-access,to the
data upon which these estimates are based. In Chapter 13 we--pre-
.sent means of improving intergovernmental coordination for the
exchange of OCS information and suggest changes in the procedures.
for reviewing development plans to increase state and local
government influence. Finally,.we recommend that the En-viron-
mental Baseline-Studies Program (EBSP) be restructured and that
the BLM establish an EBSP TaskForce.

AIR QUALITY

Preventing further degradation of air quality is one of
the most critical environmental issues facing southern.Cali-
fornia. OCS oil operations contribute substantial amounts of
reactive hydrocarbons,.aggravating an already-critical problem
of smog in the South Coast Air-Basin. Neither federal, state,
nor local agencies presently regulate air emissions from OCS
operations in federal.waters. Tanker loading operations in
particular are the largest-source of hydrocarbon emissions.
Predicting the effect on air quality from any particular OCS
operation, however, is difficult because offshore-meteorological
data are sketchy and emission estimates,for OCS-related opera-
tions vary widely.

This report recommends that OCS leasing and development
should not be permitted in.areas.or under conditions which
would allow violation of standards-or further degradation of
southern California air quality. OCS facilities should be
subject to reviews' permit controls, and emission standards
equivalent to those imposed.upon similar-facilities within
state jurisdiction@. Federal and state agencies, local juris-
dictions , and industry should7coordinate efforts to collect
the necessary data for making accurate-OCS air quality
impact projections.

SENSITIVE COASTAL RESOURCES

Key natural resources-that could be affected by OCS
development include pinniped and seabird rookeries, wetlands,
rocky intertidal areas, and offshore banks. In addition, the
Channel Islands are richly endowed natural areas which should
receive special protection from oil spills. Petroleum sanc-
tuaries should be established around seal and sea lion
rookeries. in these areas, no new@-leases should be sold-and
existing leases should be terminated. Shallow offshore banks,
important as sources of food or as unique habitats, should be
excluded from future lease sales and existing leases should be
terminated or subjected to stringent controls. High priority

should be given.to identifying critical seabird for aging areas
where a spill could endanger entire breeding populations so
that operations can be precluded or specially restricted to
protect these populations. Several actions -- including the
establishment of marine sanctuaries, legislation to create a
Channel Islands National Park, and executive orders to clear
up existing enforcement authority -- are recommended to
strengthen the protection of sensitive natural resources on the
Channel Islands. Environmental impact statements, exploration
plans, and development plans should evaluate the vulnerability
of economic and recreational resources in the event of a major
spill, considering the adequacy of existing response plans and
equipment to protect local interests.

OIL'SPILLS

Oil is discharged as the result of a variety of OCS-
related and oil transportation operations. The cumulative
effect of these activities is such that at least one major
oil spill, and many smaller spills, is likely to occur off
the southern California coast in the future. The protec-'
tion of valuable coastal resource areas is accorded high
priority in state and local planning. Such planning improves
when the trajectory of an oil spill in any given offshore area
is known. The information needed for predicting spill trajec-
tories, however, is presently inadequate. Further, once an
oil spill has occurred, those who sustain real economic losses
find that limited compensation is available under current law.

Most of the equipment available to contain an oil spill or
to clean it up once it reaches shore is owned by industry
cooperatives and stored in Santa,Barbara, Los Angeles, and Long
Beach Harbors. Some distribution of cleanup equipment close
to sensitive areas has occurred, though presently many areas
are still unprotected.

The report contains several recommendations to improve
offshore meteorological data and spill trajectory prediction
for planning purposes, as well as the re-deployment of equip-
ment to provide maximum coverage for sensitive resources in
the southern California areas. It calls for the state to
establish a testin.g program for spill containment and cleanup
equipment and to require periodic demonstrations of response
capability by cleanup organizations. The report also recom-
mends a state fund to provide compensation to spill victims,
to finance cleanup and restoration, and to support state and
local oil spill prevention and response activities.

ECONOMIC EFFECTS
Lease Sale #35 will not have a significant effect on the
economy in southern California. The-ratio of OCS-related
activity to other economic endeavors is so small that new
direct and indirect employment will be insignificant and
increases in public service demands so small that they can
be satisfied with existing excess capacity, Tax revenues
comprise a small fraction of total revenues in the affected
area, but they may be significant locally, depending upon the
sites ultimately chosen.

FACILITIES PLANNING
Unitization and consolidation offer key opportunities
for reducing the environmental effects of offshore oil and
gas development and for recovering the greatest amount of oil
and gas efficiently. Unitization is an established procedure
for coordinating the exploration, development,.and production
facilities or activities of several companies-who share a
common petroleum reservoir or geologic structure.- Consolida-
tion refers to the sharing of petroleum-related facilities,
such as pipelines, processing plants, or marine terminals.
Unitization and consolidation have occurred voluntarily when
advantageous to industry but have rarely been imposed by public
agencies on OCS developers even when public interest would
clearly dictate such intervention.

We recommend that the USGS, in cooperation with the
California Coastal Commission, adopt guidelines to ensure that
all OCS operations*and facilities will be consistent with state
and local coastal zone management programs. USGS should require
(1) unitization of all leases sold according to common geologic
structures and'(2) consolidation of transportation, storage,
,treatment, and service facilities related to OCS exploration
and development when it is both economically and environmentally
desirable. Finally, this section recognizes the ability of
industry to provide leadership on OCS development and recommends
that industry take the initiative in defining the necessary
detail for unitization and consolidation opportunities.

TRANSPORTATION

This section describes the existing oil and natural gas
transportation system in southern California and compares the
flexibility, costs, and environmental effects of pipeline and
tanker/barge transportation systems.

Because of their relative safety, California should adopt
a strong policy favoring pipelines over tankers whenever feasible
and support the development of an integrated common carrier
pipeline network linking production,areas with refining centers
and/or a west coast to mid-continent pipeline, if it is built.
Further, all fixed structures associated with exploratory and
production activities should be excluded from the Vesse'l Traffic
Separation Scheme (VTSS) in the Gulf of Santa Catalina and the
Santa Barbara Channel. If ocean floor production systems must
be used, production wells could be drilled from surface vessels
within the VTSS after appropriate precautions have been taken.

DEVELOPMENT SCENARIOS

Santa Barbara Channel.production-will probably exceed
100,000 B/D oil and 100,000 MCF/D natural gas in the early 1980s,
reaching a peak near 200,000 B/D oil and 200,000 MCF/D gas in
the mid 1980s. Additional leases and discoveries may slow the
decline, but should not require onshore facilities beyond those
necessary for the projected peak. Chapter 21 presents the state
of development, resource and production forecasts, and onshore
development options for various leased areas.

Major recommendations in this section are directed to the
State Lands Commission, the Interior Department, and the oil
industry. The State Lands Commission is urged to determine
probable remaining.lifetimes for production, processing, and
transportation facilities.on state lands, and to assist parties
interested'in the recycling of the sites from petroleum-related
uses to other uses. The Interior Department is urged to with-
draw its approval of the "offshore alternative" included in the
Exxon/Santa Ynez development plan and to prepare resource
analyses resolving a major discrepancy between the USGS and
Exxon resource estimates which are necessary to assess the
viability of Channel-wide transportation options. Industry
should bring all new Channel OCS production ashore-in two pipe-
line networks located at both ends of the Channel. It should
process production from the eastern end at the existing Mobil-
Rincon facility, and that-from the western end at the proposed
Exxon-Las Flores facility. It should evaluate the feasibility
of an onshore pipeline to carry Channel Production to refineries
as part of the EIS being prepared for Lease Sale #48. It should
develop the four subareas created by Lease Sale #35, butside of
the Santa Barbara Channel, according to lease-area plans. In
order to promote the corrdinated development and transportation
of offshore oil and gas, it should not begin development until
lease-area plans are completed.

Because San Pedro Bay leases are likely to be developed
before other subareas of Lease Sale #35, specific recommenda-
tions have been formulated: the treatment and separation of
San Pedro Bay production should be handled at an expanded
existing processing plant or at.a new onshore facility in
Huntington Beach or Los Angeles/Long Beach harbors area, and
offshore processing stations should be discouraged in this
-area because of the unnecessary risk they would represent to
navigational safety.

LEASE SALE #48

The State of California does not oppose OCS oil and gas
leasing and development per se, but does object to leasing
and development without adeqTate environmental safeguards.
In selecting the 217 tracts for Lease Sale #48, the Department
.of Interior placed oil and gas resource potential over the
concerns for environmental vulnerability expressed by California
state and local governments as well as by other federal agencies.
Oil resources from the OCS will only contribute-to the projected
west coast oil surplus, while OCS gas cannot eliminate Cali-
fornia's need to import natural gas or seek substitute fuels
to meet its natural gas demand.

Lease Sale #48 was delayed at the request of state and
local governments but was recently rescheduled. California's
position is that this lease sale should not be authorized until
Congress amends the OCS Lands Act to increase state and local
government influence over the leasing and development process
and to strengthen environmental safeguards. These amendments
are now under conside ration by Congress and could be enacted
this session.

The Interior Department should facilitate state and local
involvement in the EIS process for Lease Sale #48 by distribu-
ting all work programs and preliminary.drafts to state and local
governments in a timely fashion, as well as holding public
hearings on the DES and FES in each of the affected coastal
counties. Future lease sales off southern California should
place high priority on filling in areas leased on the Santa Rosa-
Cortes Ridge and in San Pedro Bay, but only if development can
proceed without siting permanent structures in the vessel.traffic
lanes. Further leasing in the Santa Barbara Channel should be
considered in a separate EIS as opposed to inclusion of this
area with the Southern California Borderlands now being con-
sidered by BLM in Lease Sale #48. Finally, we recommend that
tracts along the San Diego coastline should not be offered until
further baseline studies have been completed, including an
assessment of the potential for this area to economically
produce petroleum resources.

Photo opposite: Platform Houchin on the
Carpinteria Offshore field, Phillips Petroleum

PA TWO
FINDINGS AMP R MtHDATIONS
114 ;-aw

41PA PIP
All

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-LOW*

4@7

,CHAPTER 3:

MANAGEMENT
OF'OCS DEVELOPMENT

FINDINGS

CALIFORNIA HAS LITTLE CONTROL OVER OCS DEVELOPMENT. New
offshore oil and gas development will occur primarily on
federal OCS lands beyond the limit of California's jurisdiction.
Federal policy determines the timing, size, and location of
lease sales and federal-agencies re-gulate industry exploration
@.and.development activities. OCS oil and gas development plans
may include onshore processing, storage, and other facilities
subject to state and local controls, but such facilities can
be built in federal waters offshore beyond state and local
jurisdiction. Hydrocarbon emissions, oil spills, and economic
and social impacts, however, do not recognize jurisdictional
lines. The course of offshore development will determine the
onshore impacts California must bear, but the state and local
governments of California can only comment on leasing and
development plans and hope their concerns will be reflected
in the decisions of federal officials. California may gain
some control over OCS oil and gas development through the con-
sistency provisions of the Coastal Zone Management Act as
amended, but the effectiveness and scope,of those provisions
are uncertain.

LEASING BASED ON SPECULATIVE ESTIMATES. The Depaftment
of the Interior now selects and leases OCS-tracts based only on
speculative estimates of their oil and gas-potential. Esti-
mates of the resource potential of tracts are inferre'd from
geophysical and geologic data collected before the sale, but
there is no drilling to discover oil and gas until after the
tracts are leased. Without drilling, estimates of recoverable
resources depend on assumptions about the physical character-
istics of the-reservoir, the quantity of hydrocarbons-present,
and the physical properties of the hydrocarbons. Sometimes,
in areas where there has been little or no history of oil and
gas operations, test wells are drilled to collect geologic
information. These wells are intentionally drilled low on

*For additional discussion, see ChaDters 13 and 14.

geologic structures suspected of containing oil and gas, so as
to prevent the discovery of oil and gas. Prior to leasing,
however, the Interior Department rarely has any direct informa-
tion on oil and gas resources from which to judge where leasing
should be concentrated in order to increase domestic production
or to weigh the benefits against the environmental risks of
developing s-pecific tracts. In a few instances, direct infor-
mation is available from a well or wells drilled on a leased
tract into a geologic structure that also underlies an unleased
tract or from core wells drilled off southern California before
the federal-state boundary was finally established.

SALE OF EXPLORATION AND DEVELOPMENT RIGHTS. When a lease
is sold under the present system, successful bidders acquire
vested rights to explore the lease tract and to develop and
,produce the oil and gas they,discover. A decision to lease is
virtually a decision to develop.. At the time of the lease
sale, however, only general information on geologic hazards
and speculative estimates of oil and gas resources are
available. New and specific information on geologic hazards
associated with specific tracts and direct information on oil-
and gas reserves are collected and developed during the explora-
tion phase. The grant of development and production rights
with the lease precludes the federal government from using in-
formation developed in the exploration phase for judging the
benefits and risks of developing particular tracts. .
CANCELLATION OF LEASES. The authority of the Secretary
of the Interior to cancel a lease should the continuation of
oil and gas operations thereafter pose serious harm to human
life, property, mineral deposits, or the environment which was
not foreseen at the time the lease was issued is disputed.
The Secretary may cancel a lease if the lessee fails to comply
with any of the provisions of the OCS Lands Act, or of the
regulations issued under the Act, or of the lease itself, but
there is no authority for the Secretary to compensate lessees
for their costs up to the date the lease is cancelled.

INCREASING OCS OIL AND GAS PRODUCTION. Increasing oil
and gas production requires.speedy and efficient exploration
of offshore lands and development of discovered resources.
The current federal strategy to increase offshore production
relies-on leasing large areas of the OCS without any direct
information on the size, or even on the existence of underlying
petroleum resources. Our national policy should strive to
.increase oil and gas supplies from the OCS by leasing in the
most promising areas and fostering.prompt exploration and de-
velopment, not by leasing the maximum number of acres to the
oil industry on the basis of mere speculative estimates of
oil and gas potential. OCS oil and gas production can'be.
increased without undue delay, incorporating informed and
rational dectsions, under alternative leasing systems that
feature early drilling-to discover hydrocarbons and-do-not
simultaneously convey exploration-and development rights.

PRIMARY LEASE TERM TOO LONG. The@OCS Lands Act-provides

that the primaryterm of OCS oil and gas leases is for : five
years; so long as oil and gas are produced in paying quan-
tities; or, the lessee conducts drilling or well reworking
activities. The lease term is extended beyond the primary. term
therefore, if an exploratory drilling program is underway des-
pite the lack of a discovery of commercial quantities of oil
or gas. Industry has demonstrated'its ability in southern
California to obtain all necessary regulatory permits and begin
exploratory drilling, and even, in some cases, production from
OCS leases in less than one year. There is no credible reason
that exploratory drilling could not be underway on most tracts
off southern California in substantially less than five years.
Lease tracts sold in deep water to encourage development of
more advanced offshore technology or in areas like Alaska where
extreme weAther could severely restrict operations are two
exceptions.

INCENTIVES FOR EARLY EXPLORATION. In the North Sea, the
,Netherlands grants exploration licenses requiring rents that
double in the second year and double again in the sixth. The
Netherlands also requires licensees.to-spend a minimum amount
each year in exploratory efforts and to surrender a portion of
the acreage covered by the license back to the government after
a specified time. British and Norwegian-production licenses
require rental payments that escalate over time, but the rentals
may be deducted from royalty payments. Such progressive rental
schedul.es, mandatory work programs, and reductions in the
acreage covered by a lease after a specified time may be effec-
tive incentives to early exploration and development in place of
the current U.S. practice of holding rents steady on OCS tracts
without commercial discoveries.

SECRETARY'S LIMITED 'REGULATORY AUTHORITY. New or revised
regulations promulgated by the Secretary of the Interior apply
to leases issued before the effective date of.the regulations
only when they are issued for "the prevention. of waste and con-
servation of the natural resources of the outer continental
shelf." As a result, new regulations providing for review
and comment on development plans by coastal states do not
apply to OCS leases in the Santa Barbara Channel and no lease
tracts off California are affected by'regulations releasing
geologic and geophysical data and-information.

EIR PROCESS. Environmental Impact Reports prepared pur-
suant to the California Environmental Quality Act afford
California and its local governments an opportunity to analyze
the effects of onshore development proposals within state
jurisdiction. The EIR process is-not initiated., however, until
.well after development plans are formulated and industry has
chosen sites for onshore facilities. Nonetheless,, the EIR'can
be an invaluable tool for assessing alternatives and for
developing strategies to mitigate the environmental.impacts of-
specific OCS-related facilities.

3-766 58 .19

CALIFORNIA'S ROLE IN EXISTING FEDERAL LEASING AND DEVELOP-
MENT PROCESS CAN BE IMPROVED WITHOUT NEW LEGISLATION. Although
new legislation is required to effect many necessary changes
in the leasing and development process, several problems
frustrating California's participation are solely administrative
in nature:

a. Resource reports. BLM's request for resource reports
on the possible effects of leasing on the environment
or other conflicting uses of the OCS (e.g., shipping,
fishing) is usually the state's first notification of
the specific area proposed for leasing. California
received the resource report request for Lease Sale
#48 at least one month later than federal agencies.
Copies of agency responses, which are useful in res-
ponding to the call for nominations, are generally
not made available to state and local governments.

b. Call for nominations and tract selection. The Interior
partment gave an environmental-briefing to state and
local representatives on areas being considered for
Lease Sale #48, but it was held after the deadline for
responses to the call for nominations. When BLM's
Pacific OCS Office briefed state and local'government
representatives on tract recommendations being made to
the directors of BLM and USGS in Washington, the re-
commendations were presented in a vague and general
way, and no written copies of the recommendations were
provided. Thus, state and local governments had no
basis for comment on the specific tracts recommended
by BLM's Pacific OCS Office. In any case, there was
insufficient time for state and local government repre-
sentatives to prepare responses before a meeting
scheduled to discuss tract selection with Washington-
based BLM and USGS officials.

c. Environmental impact statement. State and local
governments are not involved in the preparation of
draft EISs, so their concerns are often neglected.
Public hearings are presently held too soon after
announcement of the availability of the draft EIS for
state and local governments to acquire a copy, review
it, and prepare comments.

d. Development plans. State and local representatives
@ave not been invited to discussions between USGS and
offshore-operators preceeding formal submittal of
development plans, when state and local concerns might
be accommodated more easily than after economic and
regulatory commitments have been made.

RECOMMENDATIONS

1. STATE RECOMMENDATIONS. Congress should pass legisla-

tion requiring the Secretary of the Interior to accept the

recommendations of an affected.state's governor on the five-

year leasing schedule, a proposed lease sale, exploration plan,,

or development plan unless the Secretary determines they are

not consistent with national security or the overriding national

interest.

2. PRE-LEASE DRILLING. The Interior Department should

acquire direct.information from exploratory drilling to make

tract-by-tract oil and gas resource estimates before lease

tracts are offered for sale. California should make informa-

tion from drilling in nearby state lands available to the

federal government to assist in making resource estimates.

Where direct information on geologic 9tructures underlying

a tract under consideration for leasing is not available from

a well drilled on an adjacent1ease or onshore area, at least

one test well should be drilled on those structures before

leasing. These test wells should.be drilled using the same

procedures now employed in the drilling of deep stratigraphic

test wells,off structures; i.e., the well should be drilled

by a group of,companies at a location approved by USGS. The

companies should share the costs of the well and the data from

it. USGS should receive data from the well as a condition of

the drilling permit. Companies not participating in the group
before the well is drilled should be allowed to buy the well data

after paying a proportionate share of the well costs plus a

substantial penalty.

3. AUTHORITY TO CANCEL LEASES. Congress should amend
the OCS Lands Act to give the Secretary of the Interior

authority to cancel any lease or permit at any time when con-
-tinued activity under that lease or permit would cause serious
ham or damage to any human life, to prope .rty, to any mineral

deposits, or to the marine, coastal, or human environment.
Such damage or ham should be required to outweigh the bene-
fits of continuing activity under the lease or permit and be
of a type that would not decrease over a reasonable period
of time. Lessees whose leases are cancelled should be paid
equitable compensation, based on all expenditures incurred

up to the date of cancellation less any revenues received

from production, but.not including anticipated revenues

from future production.

4. LEASING ENVIRONMENTALLY SENSITIVE TRACTS. In cases

where tracts are offered, for sale because of high oil and gas

potential in spite of high risks to the environment from de-

velopment and produ ction, the Secretary of the Interior should

have the discretion to offer leases for these tracts that

grant exploration rights and make development and production

rights subject to a determination by the Secretary that pro-

duction benefits outweigh all other costs, including environ-

mental costs. Lessees would receive the right to drill for

oil and gas, and would receive development and production

rights if the Secretary decides development should proceed.

Because of the limited and conditional nature of the rights

granted with the lease, some bidding system other than cash

bonus bidding should be used for leasing these tracts.

5. SHORTEN PRIMARY LEASE TERM. To encourage early
exploration, Congress should amend Section 8(b)(2) of the OCS

Lands Act to shorten the primary lease-term of OCS leases

from five to three years-. Congress should give the Secretary

of Interior discretion to offer leases with longer primary

terms in areas where extreme weather conditions prevail, in

deep water areas to,encourage advances in offshore technology,

.or where other extraordinary considerations would justify it.

6. RE-EXAMINE INCENTIVES FOR TIMELY EXPLORATION. Congress

and the Interior Department should consider alternatives to the

present system of collecting rents from OCS lease tracts without

commercial discoveries of oil and gas, including progressive rental

schedules, mandatory work programs, and a requirement that a portion

of the leased acreage be given up after a specific time.

7. APPLY NEW OR REVISED REGULATIONS RETROACTIVELY. Conaress

should amend the OCS Lands Act to authorize the Secretar.v of the

Interior to prescribe and amend at any time such rules and regula-

tions as he or she determines to be necessary and proper for the

purposes of the Act and to apply such rules and requlations to all

operations conducted under leases issued or maintained under the

provisions of the Act. Regulations designed to serve purposes other

than to conserve the natural resources of the OCS or to prevent waste

e.g., to enhance the role of State and local governments in the OCS

leasing process or to ensure safe OCS operations -- could then be applied

to leases existing at the time the regulations are issued or revised.

To protect the legitimate and vested proprietary rights of lessees,

however, leases should not be subject to forfeiture or cancellation

for the violation of regulations not in effect on the date the lease

was issued. Regulations aP.Dlied to leases issued before the effe ctive

date of the regulations sbould be enforced, on those leases, by strong

penalties.

8. EIR PREPARATION AND CONTENT. Environmenta 1 Impact

Reports prepared in conjunction with applications to site
OCS-related facilities should carefully examine alternatives

to the proposal and possib le strategies for mitigating impacts,
including consolidation potentials. Analysis of mitigating

strategies should be conducted in sufficient detail to provide

a basis for formulating permit conditions. Regardless of

whether a state, county, or city agency serves as the lead agency

for an EIR, all agencies with permitting authority over the

facility should be involved in preparation of the EIR from its

inception.

9. IMPROVING STATE AND LOCAL ROLE IN PROCESS.. The Inter-

ior Department should act now, under existing author-ity, to

make the following changes in the leasing and development

process:

a. Resource reports. Issue resource reports to the

state at the same time they are issued to federal

agencies. Provide copies to the states of all agency

responses.

b. Call for nominations and tract selection. Hold an

environmental briefing for state and local represen-

tatives on the lease area before nominations are

due. Provide the state with copies of all responses

to the call for nominations,from local governments
and the public. Provide the state with a written

copy of the tract selection recommendations made by

the OCS Area Office. Increase from two to three weeks

the time available to state and local officials to

prepare responses to tract recommendations of the BLM

and USGS area offices before meeting with Interior
officials in Washington.

c. Environmental impact statements. Create an EIS task

force with representatives of state and local

government, the public, and industry to assist in the

development of work programs, the selection of con-

tractors, and review of drafts. Hold public hearings

on a draft EIS no less than 45 days after it becomes

available.

d. Development plans. Invite state and local represen-

tatives-to participate in informal discussions with

offshore operators and USGS personnel'before formal

submission of development plans.

CHAPTER 4:

ADEQUACY
'OF DECISION
INFORMATION

ACCESS TO R@'ESOURCE INFORMATION

FINDINGS

RESOURCE.ESTIMATES NECESSARY FOR LEASING DECISIONS. Before
tracts are selected for leasing, resource estimates are necessary
for devising a leasing strategy that concentrates exploration and
development efforts in themost promising areas-and for weighing
estimated benefits against the environmental risks of developing
sensitive lease tracts.

USGS HAS DATA. The USGS now receives all the geologicand
geophysical data and information gathered by OCS explorers and
lessees. These data are held confidential, with only generalized
interpretations publicly available from USGS. Published USGS
resource estimates are flawed by their timing, level of detail,
.and comparability, and are of.little value to state and local
governments attempting to plan for onshore development and to
participate activelyi:n the federal process for selecting and
leasing OCS tracts.

PLANNING BASED ON RESOURCE ESTIMATES. OCS resource estimates,
reserve estimates, and production forecasts are fundamental to
planning for onshore facilities by state and local government. The
data and.information.necessaryU prepare these estimates are not
available to either the State of California or to local governments.
California is forced to rely on the Department of the Interior and
individual oil companies to provide this information.

NEED FOR DETAILED DATA. The Interior Department invites
state and local comments on a range of pre-lease'activities to
identify environmental concerns and to select tracts for the
lease'sale, but state and local comment.on individual tracts is
impossible without detailed resource estimates or access to geo-
physical and geologic data and information.

*For discussion, see Chapters 13 and 14.

TIMING. The Interior Department publishes OCS estimates
and forecasts irregularly, when needed for Environmental Impact
Statements or other Interior Department publications. Under
present policy, these analyses are not prepared or revised on
a systematic basis and do not incorporate new information
gathered during exploration and development, or even reflect
such basic circumstances as the failure to lease large areas
included in the resource estimates made before a lease sale.

DETAIL INSUFFICIENT. USGS does not publish either resource
or reserve estimates for individual tracts, leases, units, or
structures. Instead, it publishes estimates covering multiple
areas, even though individual estimates may have been prepared
internally. At this gross level, it is impossible for state and
local analysts to correlate these estimates with new information
pertaining to specific individual fields or tracts.

ESTIMATES NOT COMPARABLE. Theestimates and forecasts which
USGS has prepared are conflicting and con Itradictory (see Chapter
14). Estimates for the southern California OCS draw from dis-
parate data bases and use different.assumptions and methods, so
that useful comparisons cannot be made either between various
USGS estimates, or between USGS estimates and those available from
other sources.

CONFIDENTIALITY-OF DATA NOT REQUIRED. The confidentiality
of geologic and geophysical data and information it based upon
Interior Department regulations rather than any statutory re-
quirement. Neitherthe OCS Lands Act nor the Freedom of Infor-
mation Act requires that such material be held confidential.

SECRETARY OF INTERIOR'S AUTHORITY. Data and information
presently held bY the Interior Department are subject to re-
strictions established by the contractual arrangements under
which,they were obtained. These generally call for confidential-
ity, though it is arguable that the Secretary's authority over
OCS operations could allow the collection and release of such
material from existing leases without that restriction. For
future exploration permits'and leases, the Secretary has author-
ity to obtain OCS data and information under conditions which
allow for public release in any manner deemed-appropriate.

OFFSHORE DATA VALUABLE. Geologic and geophysical-data and
information are marketable commodities. Geophysical exploration
is frequently conducted prior to a lease sale by independent
contractors who collect,the information on a speculative basis
for sale to potential bidders. Fairness and maintenance of
exploration incentives justify protecting contractors and their
clients from indiscriminate publication. After a lease sale,
geologic information is generally collected by OCS lessees who
barter such information extensively among themselves. Lessees
feel that they have purchased exclusive rights to geologic and
geophysical data and information from their lease, including
well data. This information is valued primarily for the competi-
tive advantage it affords when nearby tracts are offered in

future lease sales and for negotiating transportation and process-
ing agreements. Advance notice of any disclosure practice would
allow lessees to adjust bids if necessary to assure that no un-
fairness results.

CALIFORNIA STATE AGENCIES. The California Division of Oil
and Gas and the State Lands Commission have the expertise to
analyze and interpret geologic and geophysical data and informa-
tion, and the capability'to handle that information in a confiden-
tial manner, as th'ey have for state tidelands leases. At present,
however, they do not h'ave the manpower or f'unding necessary to
undertake large scale analyses of OCS,data and information.

DATA ANALYSIS EXPENSIVE. Analysis of geologic and geo-
physical information is costly. Duplication of Interior Depart-
ment analyses of OCS data by state or local agencies would be
wasteful.

NEED FOR STATE ACCESS TO INTERIOR DEPARTMENT DATA. State
expenditures for analyses of geologic and geophysical data and
information would be justified in specific instances where the
Interior Department does not make public updated and detailed
resource and reserve estimates and production forecasts or where
conflicts between industry and Interior Department estimates
frustrate the resolution of disputes over OCS leasing and develop-
ment, e.g. the Santa Ynez controversy. Although such cases will
probably occur infrequently, state agencies will need access to
Interior Department data and information when they do.

RECOMMENDATIONS

10. ANNUAL RESOURCE AND RESERVE ESTIMATES. The Interior

Department should develop and publish annually updated resource

and reserve estimates and production forecasts for all leased

areas.. For areas without discoveries, resource estimates should

be provided by structure, identifying the leases affected. For

leases with credited discoveries, reserve estimates and production

forecasts should be provided by field. These reports should

specify the assumptions and generally identify the data and infor-

mation used in making the estimates.
11. POST-SALE ESTIMATES. Immediately after a lease sale,

the Interior Department should publish the tract-by-tract resource

estimates used in evaluating bids so that.pre-sale resource esti-

mates can be revised to reflect the tracts actually leased.

12. DISCLOSURE TO CALIFORNIA. The Interior Department should

provide California with access to all geologic, geophysical,

and well test data and information the Department has. This

access should be conditioned to assure the confidentiality of

these data and information. After the pertinent tracts

are leased, the state must be allowed, when necessary, to

disclose oil characteristics and other factors which may affect

development., processing, and transportation options. These

include detailed resource and reserve estimates and production

forecasts, based on interpretations of the data by the California

State Lands Division or the California Division of Oil and Gas.

13. FUTURE LEASES. Future lease sales should include in

their terms, under conditions to assure confidentiality, a stip-

ulation providing for the release of geologic, geophysical, and

well test data and information to California after the lease is sold.
14. FUTURE EXPLORATORY PERMITS. Future geologic and geophysi-

cal exploration permits should include a provision allowing the

state access to all data and information provided to the Interior

Department under stringent conditions to ensure confidentiality.

This will enable California to participate effectively in the

pre-leasinq selection process while at the same time assuring

the permittee that the market potential of his exploration efforts

will not be substantially reduced.
15. INDEPENDENT-.INTERPRETATIONS. The California State.Lands

Division or the California Division of,Oil'and Gas shoul'd analyze

and interpret geologic and geophysical data and information for

the California,state government when independent resource and

reserve estimates are needed.

16. LOCAL PERMITTING AGENCIES. Local permitting agencies

should consider the feasibility of requiring permit applicants

to submit necessary geologic and geophysical data and information,

including interpretations, to the agency or a mutually agreed-upon

third party for evaluation where such information is needed to

act on the permit application and not otherwise available. Such

information may be needed to formulate conditions for expansion

of onshore facilities, to determine whether the proposed facility

can accommodate foreseeable needs, or to plan for consolidated

use of facilities.

D E V E L 0 P M E N T P L A N S

FINDINGS

LEARNING ABOUT DEVELOPMENT. There is no formal, ongoing
process for adequately informing state and local governments
about the progress and expected impacts of OCS development.
The willingness of offshore operators to cooperate informally
in providing information about proposed development varies
widely.

NEW REGULATIONS. I't was not until late 1975 that the
Interior Department issued OCS Order #15 requiring offshore
operators to disclose even the broad outlines of their develop-
ment plans to state and local officials. The new order does
not apply to any Santa Barbara Channel leases because they were
sold prior to November 1975 and, even for leases sold after
that date, does not provide for adequate disclosure and analysis
for state and local planning purposes.

GENERALIZATIONS ONLY. Operators covered by the new
regulations are requT-red to disclose only the -general outlines
of their development proposals. The regulations,do not provide
for the disclosure of-site-specific plans for onshore develop-
ment, reserve estimates, or production forecasts for an assess-
ment of economic effects or for any description of transportation
plans. The general information required under the regulations,
while an improvement, is not sufficiently precise to assure
California the information necessary to evaluate offshore develop-
ment plans or,to plan adequately for the ensming onshore impacts.

LIMITED-REVIEW. USGS regulations provide the state only
60 days to comment on proposed development plans. The period is
too short to allow adequate analysis, and the withholding of
geologic and geophysical information precludes an independent,
assessment of technical aspects of the proposal.,

RECOMMENDATIONS

17. DETAILED PLANS AND ESTIMATES. USGS should require oper-,

ators to submit to California site-spetific plans or options
for'offshore operations and onshore faci,lities, plans to utilize

existing or expanded fac,ilities in addition to new facilities,

.plans to transport oil after processing, and detailed estimates

of economic effects of offshore oil and gas development along

with the development plan.

18. LONGER REVIEW PERIOD. The time period for state review

of development plans should be lengthened to 120,days, to begin

upon receipt of the development plan by the state and to run con-

currently with USGS review.

19. LEASES SOLD BEFORE NOVEMBER 1975. USGS should revise the

regulations to allow California to review and comment on develop-
ment plans for all' leases, in offshore California, regardless of

the date they were sold.

E N V I R 0 N M E N T A L B A S E L I N E S T 0 D I E S

FINDINGS

ENVIRONMENTAL BASELINE INFORMATION. Southern California OCS
leasing and development decisio@s -have been made on the basis of
incomplete environmental data and information. Environmental
Impact Statements (EISs) have failed to identify fully southern
California's critical environmental, commercial, and recreational
resources and their sensitivity to oil and gas production activities.
Thus it is difficult to make trade-offs between resource preservation
and energy supply goals and to develop impact mitigation strategies.
This inhibits constructive state and local government participation
in tract selection, leasing, and development decisions.

POTENTIAL SOURCE OF INFORMATION. The Environmental Baseline
Studies Program is a potential source for the detailed environmental
.information required by federal, state, and local governments in
making leasing and development decisions. However, the major goal
of the program is to produce information after tracts are.10ased
and committed to development.

PROGRAM GOAL. The Environmental Baseline Studies Program
goal of evaluating post-OCS development environmental con-
sequences of OCS development is much less important to south-
ern California state and local governments than the goal of
having sufficient information on which to.base pre-leasing and
pre-development decisions.

RECOMMENDATIONS

20. RESTRUCTURE PROGRAM. The Environmental.Baseline Studies.

Program should be restructured to fulfill federal, state, and

local'government needs for site-spe cific information on.:

a. location of marine mammal and bird habitats;

b. identification of critical non-mineral and recreational

resources;

c. location of areas critical to the preservation of com-

mercial and recreational fisheries; and,

d. the potential of o il and gas development at particular

sites to disturb these habitats, resources, and areas,

especially those which are unique and irreplaceable.

This information should be published and made available to the

public and used in selecting tracts to be included in the EIS.

21. ESTABLISH TASK FORCE. BLM should establish an Environ-

mental Baseline Studies Program Task Force which includes repre-.

sentatives of California state and -local governments, industry,
and the scientific community to:

a. determine priorities and formulate work programs5

b. review RFPs and select contractors, and5

c. disseminate information to all interested parties in

a.systematic and timely manner.

STATE AND LOCAL PLANNING
INFORMATION AND RESEARCH NEEDS

FINDINGS

EARLY COMMUNICATION. Early exchange of information among
all affected parties -- federal, state, and local government and
industry -- can reduce conflicts later in the leasing and per-
mitting process when delays are more critical economically.

ADVANCE NOTICE. Publication of notices in the Federal
Register and informal contacts do not assure that all appropriate
state and local governments and other interested parties will be
alerted in time to review and comment on proposed federal actions
within the designated time. By the time governments have received
notice, reviewed the proposal, prepared comments, and obtained
necessary approval from the County Board of Supervisors, City
Council, or Planning Commission, deadlines for comments have
frequently passed. State agencies encounter similar delays.

FEDERAL ORGANIZATION. OCS responsibilities and functions
are spread among several federal agencies. State and local govern-
ment agencies seeking information on federal OCS policy or tech-
nical information often must contact a number of these federal
agencies. Frequently, the federal agencies are slow to respond,
refer the inquiry elsewhere, or are not well enough informed to
direct the inquiry to the appropriate source for response. This
results in frustration and delay, and further limits the ability
of state and local government officials to express their views on
federal and industry proposals for OCS leasing and development.

STATE ORGANIZATION. In California, OCS policy making.and
regulatory functions are spread amona numerous state agencies,
and there is no systematic means of coordination among them.
Local governments, federal government personnel, and industry
must, therefore, contact a number of state agencies in order to
obtain or convey information on OCS-related proposals or actions.

TECHNICAL CAPABILITY. Once aware of a need to respond to
a proposed federal or industry action, California state and
local agencies find they lack staff time and expertise, suffici-
ently detailed description of the proposal, or adequate technical
information about the potential impact of the proposal (whether
it is leasing, exploration, or development) to prepare a substan-
tive response, recommend mitigating strategies, or propose feasi-
ble alternatives. Consequently, federal officials often charac-
terize state'and local comments as too vague and generalized to
merit serious consideration.

EXCHANGE OF INFORMATION AMONG STATES. Coastal states have
experienced OCS development to varying degrees, and a number of

coastal states are performing OCS-related research projects with
federal funds. These states can benefit from sharing experiences
and information, but no mechanism presently exists to facilitate
communication amono them.

INFORMATION ON FEDERAL FUNDING. Funds are available from
various federal agencies to support state and local government
OCS-related projects, but there is no systematic mechanism at
either the federal or state level,to identify available funds,
make state agencies and local governments aware of them, or
assist state ageRcies and local governments to obtain them.

PRIVATE CONSULTANTS. Federal agencies often contract
directly with private consultants to con-duct OCS research de-
signed to meet the information needs of California state and
local governments. These-consultants in turn seek interviews
and request information from state and.local qovernment person-
nel in order to carry out their tasks. In some instances, state
and local governments are then denied access to.subsequent work-
ing drafts prepared by the consultant.and must await formal re-
lease by the contracting agency to receive the final product.
This manner of developing information for state and local govern-
ments is burdensome to,them. The federal government would fulfill
state and local government needs better by contracting with them
directly to conduct the required research.

RECOMMENDATIONS

22. FEDERAL COORDINATION. Interi,or Department's Bureau of

Land Management, in coordination with the Commerce Department's

Office of Coastal Zone Management, should establish an OCS Infor-

mation Clearinghouse to:

a. provide notification of significant OCS leasing and

.development actions;

b. provide an up-to-date account of OCS-related research

being conducted by the federal government, state or

local governments, academic or private institutions,

and industry; and.,

c. provide a complete guide to federal financial and

technical assistance for OCS-related planning and

efforts to mitigate i-mpacts.

23. STATE COORDINATION. The Governor should ask the

California Coastal Commission to assume responsibility for:

4-76658 35

a. coordinating state and local agency responses to@PrODOSPd

federal government and industry actions on the OCS;

b. disseminating information among state agencies and pro-

viding local jurisdictions with technical assistance to

participate in OCS leasing and development decisions

and to anticipate that development in local coastal plans;

c. assisting state, regional, and local government agencies

to identify and obtain federal funds to support OCS-

related projects and programs; and,

d. maintaining communication and exchanging information with

other states on OCS-related matters.

The Coastal Commission should be allotted additional funds and

staff positions sufficient for carrying out these responsibilities.
24. BESPONDING TO LEASE SALES. In responding to OCS leasing

proposals, state and local agencies should focus their attention

on identifying:

a. specific tracts where the potential for adverse 6-ffects

or conflict,with current use is so.great that development

absolutely should not take place;

b. specific tracts where leasing and development can take

place under prescribed stipulations and regulations; and,

c. alternatives to the proposed action, including specific

conditions that should be imposed or mitiqation strategies

that should be pursued if the action is permitted to qo

forward.

25. FEDERAL FUNDS. Federal acencies should make funds avail-

able to California state agencies and southern California local

governments.to meet needs for:

a. support of staff at the state and county level to assist

participation in the OCS leasing and development process

and to review and prepare comments on environmental impact

statements and proposed exploration and development actions;

b. updating baseline emissions inventories, establishment of

air quality monitoring stations, and collecting meteoro-

logical data; and,

c. assessment of oil spill contingency capabilities and

development of contingency plans.

26. USE OF STATE AND LOCAL AGENCIES FOR FEDERAL RESEARCH.

Federal agencies should contract directly.with California state

or local agencies to accomplish research projects designed to

meet state and local government information needs. Proposed work

programs for such projects should be circulated to.state and local

agencies for review prior to completing Pequests for Proposals

(RFPs). State and local government agencies should receive RFPs

as do private consultants, and those agencies that qualify

should be given preference over qualified private consultants

when the contract is awarded. Regardless of who performs the

work, state and local government agencies, industry, and other

interested parties should have access to the work in progress

and the draft product fo r comment and review prior to its final,

formal release.

CHAPTER 5:

AIR QUALITY

FINDINGS

AIR QUALITY IMPACT CRITICAL. Preventing further degrada-
tion of air quality is one of the most critical environmental
issues facing southern California. OCS oil production will
aggravate an already critical photochemical oxidant problem,
but additions to the state's natural gas supply will help
alleviate sulfur oxide and ozone problems caused by natural
gas users switching to other fuels.

OCS AIR POLLUTION. OCS oil operations (production,
processing, and transportation) generate substantial amounts
of reactive hydrocarbons. Since the dominant winds in south-
ern California blow onshore from the northwest, OCS emission
contributions must be taken into account in medium- and long-
range air quality planning for southern California, from
Santa Barbara to San Diego. While there is considerable con-
troversy about the actual level of emissions from each type
of operation, it appears that tanker loading i.s the largest
OCS-related source of reactive hydrocarbons.

NEW SOURCE REVIEW. Major new OCS-related facilities
proposed for construction within state jurisdiction in south-
ern California will be subject to individual review under
New S7ource Review rules (NSR). Because of the -area's chronic
violation of oxidant standards, those sources.,emitting more
than 15 pounds per hour or 150 pounds per day of reactive
hydrocarbons will not be allowed construction permits unless
the facility falls within an exemption or the applicant can
provide offsetting emission reductions from other sources
acceptable to the local APCD, the ARB, and the EPA.

EMISSION FACTOR CONTROVERSIES. Permits for the con-
struction and operation of OCS-related facilities within state

*For additional background, see Chapter 15 and Appendix 3.

jurisdiction may require an analysis of the proposal's air
quality impact. Industry and government sources disagree
over the factors which should be used in estimating emis-
sions for these analyses. The oil industry believes pub-
.lished factors are too high and has undertaken a research
program to establish more reliable numbers. The Western
Oil and Gas Association is sponsoring research on tanker
.loadingemissions in Ventura and San Luis Obispo Counties
which should be published shortly, and the American Petro-
leum Institute is sponsoring research on fugitive emissions
from platforms and onshore facilities which should be avail-
able in early 1978.

TANKER LOADING EMISSIONS. When crude oil tankers are
empty, the residue in the cargo compartment vaporizes to
form a rich hydrocarbon blanket.which is displaced into the
atmosphere when the cargo hold is filled with crude. No
technology presently exists to recover these displaced
vapors or to prevent their formation and emission. The volume
and concentrations of emissions, however, may be reduced
somewhat by slowing the loading rate and by only partially
filling cargo compartments.

REGULATION OF OCS SOURCES. Offshore operations beyond
the state's three-mile jurisdictional limit enjoy a de facto
Clean Air Act exemption. The reviews, permit controls, and
emission standards applied by federal, state, and local
agencies onshore are not applied to OCS operations. EPA
Regional Counsel Opinion 293 (September 15, 1975) affirmed
the legality of such controls, but subsequent analyses have
raised questions about that position. The USGS, which over-
sees OCS operations, has no regulations specifically governing
either the equipment which must be installed or the operation-
al procedures which must be observed to minimize air pollution.
In the opinion of its General Counsel, the EPA can regulate eir
emissions from OCS operations as a condition for issuing a
water discharge permit (NPDES), but the EPA has never asserted or
tested this authority on any OCS facility.

OFFSHORE METEOROLOGY. Offshore operations in southern
California may adversely affect air quality in southern Santa
Barbara County, coastal Ventura County, and the South Coast and
San Diego Air Basins. A common problem of the four APCDs in
this area is that offshore meteorological conditions and air
transport mechanisms are poorly understood, making it difficult
to assess the effect of any particular offshore development
proposal. None of the APCDs has sufficient staff or fund-
ing to perform the research necessary for these assessments
throughout the entire offshore area.

RESEARCH NEEDS. The local APCDs in southern California have
identified three key research and equipment needs for improving
OCS air quality impact assessment: better emission factors,
improved offshore meteorological information, and mobile monitor-
ing stations.

BECOMMENDATIONS

27. PROTECTING AIR QUALITY. OCS.leasing and development

should not be permitted in areas or under conditions which would

allow violation of standards or further degradation ofsouthern

California air quality.

28. REGULATING OFFSHORE FACILITIES.. OCS facilities should

be subject to reviews-5 permit controls, and emission standards

equivalent to those imposed upon similar facilities within state

Jurisdiction. A number of avenues- are available to approach

this objective:

a. the Interior Department could develop regulations and

operating orders explicitly addressing equipment and

operating procedures for minimizing air pollution under

its general authority to adopt regulations for "the. con-

servation of natural resourcesil

b. the EPA could impose air-related conditions under its NPDES

permit process;

c. Clean Air Act amendments could specify the permits,

reviews, and standards which will be-applicable to OCS

facilities;

d. OCS Lands Act amendments could explicitly provide for

the application of state air pollution permits, reviews,

and standards to OCS facilities likely to contribute to

onshore pollution; and,

e. the state and-local APCDs.could attempt to impose controls

over OCS facilities affecting onshore air.quality by

adopting emission limitations as part of the State Imple-

mentation Plan and submitting them to the EPA for approval,

anticipating a@legal challenge on the issue of whether

the Clean Air Act established jurisdiction for such

action.

29. AIR QUALITY ANALYSIS. Environmental Impact Statements

prepared in conjunction with OCS leasing and development proposals

should analyze OCS air quality impacts in suffici-ent detail to

enable EPA, ARB, and local APCDs to determine if the proposal will

cause a localized violation of an air quality standard or inter-

fere regionally with the attainment or maintenance of air quality

standards. This analysis should be accomplished through the

cooperative efforts of BLM, EPA, and ARB.

30. COORDINATE EFFORTS. Federal and state agencies, local

jurisdictions, and industry should coordinate efforts to collect

meteorological data, standardize emissions factors, and develop

reliable methods for making accurate OCS air quality impact

projections. This should be used in the development of an EPA-

approved State Implementation@Plan.

31. TANKER EMISSIONS. The ARB should undertake an assess-

ment of tanker contributions to oxidant formation in California,

including the potential for enforceable controls restricting

emissions to meteorological.conditions and coastal areas where
adverse effects would not exacerbate an already serious problem.

32. MARINE TERMINAL PERMITS. Permits for construction and

operation of new or expanded marine terminals for handling OCS

@oil should be conditioned on operating controls or compensatory

emission reductions that take into account tanker-emissions during

loading, unloading, and operations.

33. METEOROLOGICAL STUDY. The federal government should

fund a cooperati.ve study by the four southern California coastal

APCDs of offshore meteorological conditions and air transport

mechanisms. Such a study should provide information in a format

useful to each of them for making air quality impact analyses of

proposed offshore development.

34, PLATFORM MONITORING STATIONS. Industry should install

wind monitoring and recording devices on offshore facilities as

part of a coordinated program to improve the available data base

(see Recommendation 8, Chapter 7, for additional details). Addi-

tional meteorological equipment, such as radiosondes

to measure temperature, humidity, and wind profiles to around 1000

feet, and insolation measuring devices should be operated

on platforms at locations sufficient to obtain an adequate data

base of meteorological conditions in the OCS.

35. FEDERAL RESEARCH PROCEDURES. The ARB and local APCDs shculd

be given an opportunity to review and respond to all federally

issued RFPs for air quality research to be performed in California

and to review interim and final reports on the research. Federal

government agencies should place the highest priority on using the

ARB or local APCDs rather than private contractors to conduct

such research, and to evaluate research in progress.

CHAPTER 6:

SENSITIVE
COASTAL RESOURCES

FINDINGS

MANY HABITATS SENSITIVE. Many important habitats found
in the Southern California Bight are sensitive to petroleum
development activities as well as to oil spills resulting from
these activities. Pinniped and seabird rookeries, wetlands,
rocky intertidal areas, and offshore banks are especially
vulnerable.

OFFSHORE BANKS. The Southern California Bight is an
atypical continental margin. Its highly irreqular submarine
topography is distinctly different from the shelf-and-slope
configuration characteristic of most of the North American
continental margin. Numerous rocky outcrops form subsurface
ridges and banks shallow enough to support complex and highly
productive assemblages of plants and animals within the photic
zone. These offshore banks are important to-commercial fish-
ing interests and constitute essential habitats for certain
unique marine species. They are vital feeding grounds for
seabirds and pinnipeds, especially during the breeding season.
These areas include Osborne Bank, Tanner Bank, Cortes Bank,
Thirty-Mile Bank, Forty-Mile Bank, North-East Bank, Lasuen
Knoll, and shallow banks in the Santa Rosa-Cortes Ridge
area.

SEABIRDS. Oil spills pose a tremendous hazard to all
marine-asso-ciated birds. Seabirds are particularly vulnerable
to oiling and subsequent death as a*result of exposure. Birds
breeding on the Channel Islands depend exclusively on adjacent
waters for foraging. Foraging needs are highest during the
nesting season. According to the preliminary findings of BLM's
baseline studies, many seabird populations are already in
jeopardy. An oil spill during the nesting season could
devastate those populations.

*For additional discussion, see Chapter 16.

PINNIPEDS. The Southern California Bight possesses the
world's largest and most diverse pinniped community in temper-
ate waters. Human activity in southern California has forced
these marine mammals to abandon their historic mainland
rookeries. Today, seals and sea lions breed and haul out almost
exclusively on the Channel Islands. Petroleum-related activi-
ties, including crew staging and transport, seismic exploration,
drilling, platform assembly and installation, pipe laying,
tanker lightering, vessel repairs, and other disturbances near
major breeding and haul out grounds on the Channel Islands
could eliminate the last remaining breeding areas in southern
California for sea lions, fur seals, and harbor seals.

ROCKY INTERTIDAL AREAS. Tide pools and their unique inha-
bitants are a heavily utilized marine resource in California.
In southern California, rocky intertidal areas exist in limited
and widely dispersed coastal sites. These areas have consid-
erable scientific, recreational, educational, and ecological
value. Many marine species depend on tide pools during some
part of their life cycle.

COASTAL WETLANDS. Many studies have underscored the need
to protect and maintain California's remaining coastal wetlands.
Estimates of wetland acreaqe lost to urbanization in southern
California range from 75 to-90%. All sources agree on
the critical value of the remaining marshes and mudflats, which
provide essential habitats for hundreds of fish and wildlife
species, including several rare and endangered species.

WETLAND PROTECTION ESSENTIAL. Because of their critical
value and their vulnerability to damage, wetlands
require special protection from oil spills. If contamination
occurs, cleanup operations alone could cause further damage to
the wetlands because cleanup cannot be accomplished without
significant removal of vegetation. This would disrupt nesting
and feeding areas, particularly during breeding and migration
seasons. If cleanup is not undertaken, the dense vegetation
and thick sediments of a marsh tend to entrap oil and release
it periodically during storms or other disturbances over months
or even years.

CHANNEL ISLANDS. The eight Channel Islands are of great
ecological significance because of their location astride a
major biogeographic transition of the Pacific Coast, the Point
Arguello-Point Conception break. The Channel Islands support
several species of terrestrial flora and fauna not found on the
mainland. The intertidal and subtidal areas surrounding the is-
lands support many unique one degree endemics (organisms with a
north-south range of 60 miles) and an abundance of diverse
tidepool plants and animals. The islands also provide refuge
for animals with low tolerance for human disturbance.

SAN MIGUEL ISLAND. San Miguel Island and its associated
rocks are the most important pinniped habitats in southern
California. Six species of seals and sea lions inhabit the

island, and five species breed there. The microclimate and topo-
graphy of San Miguel make it an ideal habitat for both northern and
southern pinniped species. Such diversity in one geographical
area is unique. Eight species of sea birds also depend on the
Island for breeding and nesting.

SAN MIGUEL JURISDICTION. The United States Navy owns San
Miguel Island, adjacent Prince Island and associated rocks, but
the National Park Service (NPS) manages them as a unit of the
Channel Islands National Monument. The NPS management is governed
by a cooperative agreement between the two federal agencies. Under
the agreement NPS is primarily responsible for enforcing federal
laws to protect archaeological resources, the flora and fauna and
the natural environment of the islands. Living marine and terres-
trial resources'are managed by the NPS in cooperation with federal
and state fish and wildlife agencies.

SANTA BARBARA ISLAND. Santa Barbara Island is a major
breeding and haul out ground for pinnipeds as well as an impor-
tant nesting area for nine species of sea birds. Osborne Bank,
just south of the island, is an important fishing area and one
of the three areas in the Bight where the rare purple coral is
found.

ANACAPA ISLAND. At this time, Anacapa Island is the only
consistently used California nesting and breeding area for the
endangered Brown Pelican, and provides nesting habitat for six
species of marine and shore associated birds.

RECOMMENDATIONS

36. IDENTIFY FORAGING AREAS. BLM's baseline studies should

give high priority to identifying the specific foraging areas of

seabirds by species and density of use. In areas where foraging

levels are so high that a major spill could endanger the breeding

population of any southern California sea bird:

a. no further.leases should be offered;

b. existing leases should be terminated through repurchase;

and,

c. existing leases not terminable should be regulated so

that drilling operations do not take place during the

critical spring-summer breeding season.

37. ESTABLISH PINNIPED SANCTUARIES. A sanctuary of at

least six miles should be established around all pinniped breeding

grounds. A larger sanctuary should be established around San

Miguel Island to preserve its vital role as a major breeding

ground for pinnipeds and sea birds. Within these sanctuaries,

no new leases should be offered, existing leases should be

terminated or repurchased, and oil-related disturbances such

as boat traffic, pipelining, and anchorage for repair and main-

tenance should be prohibited.

38. PROTECT OFFSHORE BANKS. In order to protect the

unusual and highly productive shallow areas of the offshore

banks within the photic zone, USGS should not approve any per-

mit for the location of a structure within or above the seventy

meter depth contour of the Osborne Bank, Tanner Bank, Cortes Bank,

or Santa Rosa-Cortes North Ridge until studies on the Dotential

effects of oil and gas operations on the biological communi-

ties of the offshore banks are completed and specific protec-

tion strategies are devised for those resources. Furthermore,

because the red and purple forms of Allopora coral found on

the offshore banks are so unusual and slow to recover from any

damage, the Interior Department should survey the locations of

these coral communities on all offshore banks and not permit

any structure to be placed in these locations.

39. PROTECTION OF SAN MIGUEL AND PRINCE ISLANDS. To strengthen

management capability and responsibility in a single agency, owner-

ship of these islands should be transferred from the Department of

the Navy to the Department of the Interior for administration by

the National Park Service.

40. CREATE CHANNEL ISLANDS NATIONAL PARK. A Channel

Islands National Park including San Miguel, Anacapa, Santa

Barbara, Santa Cruz, Santa Rosa, and San Nicholas Islands should

be created by Congress.- The,legislation should provide appro-

priate restrictions to ensure well managed public access as well

as protection of associated'marine and terrestrial species.

41. A MARINE SANCTUARY. The Secretary of Commerce should

designate the waters within twelve miles of the Channel Islands

as a marine sanctuary under the provisions of the Marine Pro-

tection, Research, and.Sanctuaries Act of 1972 (PL 92-532) in

order to protect their value as a habitat for marine flora and

fauna, and as vital foraging grounds for pinnipeds and sea birds

breeding on the islands.

S E N S I T I V E E C 0 N 0 M I C R E S 0 U R C E S

FINDINGS

I SOUTHERN CALIFORNIA LIFESTYLE RELATED TO COASTLINE. The
southern California lifestyle is-strongly associated with the
region's marine and coastal environment. Marine recreation
is a multi-million dollar industry. Damage from a major spill
to southern California's recreational resources, including
.beaches, marinas and harbors, recreational fishing and diving
areas, and commercial fishing areas, could cause substantial
economic losses.

BEACHES. Southern California's most heavily-used recrea-
tional resource is its extensive beaches. Over 12 million
people used southern California's beaches in 1976.. Because of
their great length, beaches are impossible to protect entirely
from spilled oil. Removal of oil from beaches is a straight-
forward but labor-intensive task.

FISHING INDUSTRY Commercial and sport fishing originat-
ing from California harbors generates more than $600 million
annually through sales of the catch and the support of canneries,
retail outlets, harbor activities, and related trades. Economic
loss to the industry from a large spill could occur as a
result.of:

a. damage to commercial and sport.species;

b. destruction of larval stages of commercial and sport
species;

c. the cost of cleaning oiled vessels; and,

d. harbor closures and loss of fishing time.

RECOMMENDATION

42. FEDERAL AND INDU STRY RESPONSIBILITY. Environmental

impact statements, exploration plans, and development plans

should specifically evaluate the vulnerability of recreational

and economic resources and the spill response capabilities in

local communities potentially affected by an oil spill. Such

documents should include specific locations of exposed re-

sources, an analysis of response time, and response capability,

and competing demands on equipment use and potential economic

loss to the community.

CHAPTER 7:

OIL SPILLS

EINDINGS

MARINE OIL SPILL SOURCES. Marine sources of oil spills
off California include production facilities, tankers and other
vessels, pipelines, and marine terminal and transfer operations.
On a world-wide basis, spills from offshore production facil-
ities account for less than 3% of oil entering the oceans from
marine sources. Spills from offshore production platforms do
not occur often, but they can be very large. During the 1969
Santa Barbara Channel blowout, the largest recorded oil spill
off California, an estimated 77,000 barrels of oil were spilled.

OIL SPILLS LIKELY. The amount of oil produced, transpor-
ted, and transferred off California -- and thus the opportunity
for oil spillage -- is increasing. The number of conflicts
between different offshore oil-related activities, such as the
rigs now drilling in San Pedro Bay vessel traffic lanes, is
also increasing. The probability of an oil spill occurring at
any given time from any particular source is extremely low,
but the cumulative effect of many separate oil-related activi-
ties is such that at least one major oil spill and many smaller
spills are likely to occur off southern California in the
future.

OIL SPILLAGE CAN BE REDUCED BUT NOT ELIMINATED.. Improve-
ments in operating technologies and procedures, together wi.th
more thorough state and federal enforcement of oil spill pre-
vention regulations, can reduce substantially the number and
size of spills. After the 1969 blowout, both industry and
government took steps to reduce,the likelihood of oil spillage.
As a.result, there has not been a recorded spill from produc-
tion platforms in state or federal waters off California since
1969. Nevertheless, since many-spil.ls are caused by accident

*For detailed discussion, see Chapter 17.

5-76658
51

or human error, the risk of major spills can never be completely
eliminated..

NATURAL SEEPS. Natural seeps are a source of chronic, low-
level oil pollution in southern California waters. Estimates
of seepage rates in the Santa Barbara Channel range from 40-670
B/D. Seepage rates may be influenced by oil and gas production
operations, but existing information is not sufficient to
resolve this issue.

SPILLS LIKELY TO MOVE TOWARDS SHORE. General wind and
wave current patterns off south@_rn -California are such that
most spills -- except those originating in the Outer Banks
will move toward mainland or island coasts with a time-to-shore
of hours, days, or weeks. Natural physical, chemical, and bio-
logical forces exist which can disperse and degrade spilled
,oil, but the rates at which these forces work are generally too
slow to remove spilled oil from the water surface before it
comes ashore.

AT-SEA CONTAINMENT AND RECOVERY OF OIL SPILLS OFTEN
IMPOSSIBLE. Oil spill cleanup equipment has improved consider-
ably in recent years, but at-sea containment and recovery of
spilled oil is often impossible. The effectiveness of existing
equipment falls off dramatically if cleanup must be undertaken
at night, in fog, in storms, or in anything rougher than moder-
ately calm seas. Other factors influencing the success of at-
sea containment and recovery operations include the time lag
between the spill and the deployment on-scene of containment
booms and the training and experience of the personnel conducting
the cleanup operation.

OIL SPILLS HARMFUL. Spilled oil reduces the amenity and the
recreational and economic value of coastal and marine resources.
The biological effects of spilled oil vary widely, depending on
the unique circumstances of each spill. Oil spills always have
the potential to cause significant short-term and long-term
damage to coastal and marine life. Some crude oil spills do
not cause measurable damage. Others cause substantial damage.

INDUSTRY AND COAST GUARD CLEAN UP MOST SPILLS. Under
federal law, the-containment and removal of spilled oil in
coastal or marine waters is undertaken by the party responsible
for the spill, under the supervision and, if necessary, the
direction of the U.S. Coast Guard. During spill emergencies
the Coast Guard coordinates its activities with other federai
and state authorities through a Regional Response Team. If the
responsible party cannot be identified or is not responding
properly, the Coast Guard has the authority and the funds to
hire a spill cleanup cooperative or contractor directly. State
and local agencies do not have the funds to do this, and rely
on industry and the Coast Guard to clean up offshore spills.

STATE ROLE IN OIL SPILL RESPONSE. For spills in state or

Jederal waters, California's role during cleanup operations
is that of observer, advisor, and assistant to the Coast
Guard -- except that California has veto power over the use
of dispersants or other chemical agents in state waters.
Under California's Oil Spill Contingency Plan, which has
been recommended as a model state plan by the American Petro-
leum Institute, the Department of Fish and Game maintains
liaison between local and other state officials and the
federal and industry personnel directly involved in the
spill response.

LOCAL ROLE IN OIL SPILL RESPONSE. Of all jurisdictional
levels, local governments of coastal communities are most
directly affected by oil spills and least directly involved
in oil spill cleanup operations. Local agencies provide on-
shore logistic support for offshore containment and recovery
operations, but"do not participate in actual cleanup efforts
unless and until oil comes ashore. Coastal communities have
expressed strong concern about oil spill response procedures,
yet many coastal communities are uninformed or poorly informed
about the respective roles of federal, state, local, and
industry organizations in responding to oil spills.

USE.OF CHEMICAL AGENTS CONTROVERSIAL. Industry has
developed chemical agents intended to disperse, sink, or other-
wise modify the behavior of oil slicks. The use of these
chemical agents, especially dispersants, is the subject of
much controversy. On the one hand, chemical dispersants
promote the removal of oil from the water surface into the
water column, and thereby reduce the potential threat to
seabirds and intertidal organisms. Also, such chemical agents
are less expensive than attempting physical containment and
recovery. On the other hand, dispersants are themselves.toxic,
do not always function effectively, and if successful in
dispersing oil into the water column, their use prevents
physical removal of the oil from the water. Present state and
federal policies advocate the physical containment and recovery -
of spilled oil as a first priority. Dispersants are permitted
only in extraordinary.circumstances where their use is likely
to eliminate a direct and immediate thr 'eat to human safety or to
a particularly valuable resource which cannot be otherwise
protected. A slick moving toward a' pinniped rookery in sea
conditions prohibiting containment or removal might provide
such a case.

SPILL CLEANUP EQUIPMENT PRIVATELY OWNED. Almost all oil
spill containment and recovery equipment in California is owned
by private companies, either individually or through coopera-
tive industry associations. There are three such cooperatives
in southern California, which store their equipment in Santa
Barbara,-Los Angeles, and Long Beach harbors. There are addi-
tional cooperatives in northern California, and the Coast Guard
maintains some equipment at several of its coastal installa-
tions. State and local agencies in California do not own
significant amounts of spill.containment or removal equipment.

LITTLEBOOM AVAILABLE AT PLATFORMS. A key factor in the
effectiveness of oil spill cleanup operations is the speed with
which an oil slick-can be surrounded and contained in the water.
At present, offshore producers keep minor amounts of "first
aid" containment boom and recovery equipment on offshore plat-
forms, and rely on shore-based equipment to deal with spills
larger than five or ten barrels. This practice, sanctioned
by the State Lands Division and the U.S. Geological Survey,
builds in unnecessary delay, reducing the chances for successful
at-sea containment and recovery of larger spills.

CLEAN-UP CAPABILITY OF OIL SPILL COOPERATIVES UNKNOWN.
Industry spokesmen state that existing oil spill cleanup cooper-
atives in southern California have'the ability to contain and
recover spilled oil under most of the sea and weather conditions
occurring off southern California. The three cooperatives.were
established after the 1969 blowout, and have never had to respond
to a major offshore spill. Each cooperative does stage periodic
dernonstrations to familiarize personnel of the companies belonging
to the cooperative with available equipment, but'no cooperative
rehearses full-scale spill response procedures under simulated
emergency conditions. This being the case, the ability of the
cooperatives to contain and recover spilled oil in a timely fashion
under a range of environmental conditions is simply unknown.

NATURAL AREAS NEED BETTER PROTECTION. Spilled oil cannot
,always be kept from coming ashore. When oil moves ashore, it
is sometimes possible, through strategic deployment of contain-
ment booms, to divert oil away from especially sensitive or
valuable coastal resources and toward areas of lesser importance
or vulnerability. Harbors, marinas, and similar areas generally
receive high priority for such defensive booming because their
restricted entrances make such diversion practicable and because
oil spill damages in such areas are highly visible, easily
calculated and legally compensable. In areas of high natural
value -* such as wetlands, rookeries, or estuaries -- oil spill
damages are often difficult to appraise or to express as eco-
nomic losses, and lawful compensation is uncertain at best.
Such areas may not receive protection commensurate with their
true value. To its credit, Clean Seas, Inc. of Santa Barbara
has begun to distribute cleanup equipment at selected locations
along the coast to shorten response time and provide greater
protection for estuaries, marshes, and other vulnerable resources
within its area of response, whose configuration makes such
defensive booming practical. The other cooperatives, based in
Long Beach and Los Angeles harbors, have not yet taken similar
steps.

BETTER FEDERAL ENFORCEMENT NEEDED. The 1969 blowout was
caused by operator errors that might have been avoided if fed-
eral regulations had been properly enforced. Since the blowout,
the U.S. Geological Survey has strengthened its OCS regulations
and increased its Pacific OCS inspection force from two to 11
full-time employees. In the same period, 56 more leases have
been sold, new oil fields have been found, and new platforms

installed. Additional inspectors will be needed to maintain
adequate enforcement of OCS pollution control regulations in
the future.

OCEANOGRAPHIC AND METEOROLOGICAL INFORMATION LACKING.
Knowledge or prediction of the likely trajectories of spilled
oil off California is useful for assessing the potential effects
of air and water pollutants discharged at offshore facilities.
Data on the prevailing winds, waves, and surface water currents
in the vicinity of offshore oil-related facilities are often non-
existent or unavailable to public agencies.

CALIFORNIA SPILL TRAJECTORY PREDICTIONS INADEQUATE.
Existing oil spill trajectory analyses do not provide.an ade-
quate basis for "best possible" contingency planning. The
Interior Department did not conduct an original oil spill tra-
jectory analysis for any of its three previous California OCS
Lease Sales, but will do so as part of the environmental impact
statement for proposed Lease Sale #48.

FEDERAL SCIENTISTS STUDY SPILL TRAJECTORIES IN THE FIELD.
NOAA and the Coast Guard have recently established mobile oil
spill monitoring teams. When significant spills occur, these
teams fly to the spill and track slick movement, measuring.
winds, surface water currents, and other environmenta.1
factors. These field data can be used to verify or
correct slick trajectory predictions based'on theoretical
calculations or laboratory experiments.

LACK OF FUNDS HAMPERS FIELD INVESTIGATION OF SPILL EFFECTS.
Proper scientific field studies of the biological effects of
spilled oil are impeded by many factors. For best results.,
chemical and biological studies should be initiated within hours
or days after the oil comes ashore and be repeated at regular
intervals for at least several years. For such studies to be
undertaken, there must be available scientists with requisite
competence, inclination, freedom, and an assured source of funds.
As a practical matter, this combination of circumstances almost
never exists -- the West Falmouth spill study being one of the
rare exceptions -- and such studies are either foregone entirely,
begun after weeks or months of delay, or terminated before long-
term effects can be established. In sum, most oil spills are
not properly studied, and neither short-term nor Tong-term
effects are known with-any degree.of precision. One obstacle
which can be removed is the delay or premature termination of
such studies due to lack of funds. Were public funds available
to initiate studies promptly and to maintain them for as long
as necessary, determining the actual effects of spilled oil on
coastal and marine life woOd be substantially less difficult.
Establishment of a public fund to support research would help
provide a sounder basis for public policy Oecisions.on offshore
activi ti es. wi th oi I spi I I potenti al

COMPENSATION FOR SPILL DAMAGES DIFFICULT. For individuals

and public entities damaged by oil spills, existing state and
federal legal remedies are woefully inadequate. Many of the
real economic losses suffered in a major spill are not recog-
nized as "damages" subject to recovery at law. Even for
legally compensable oil spill damages, a victim must be ready
to undertake protracted and costly litigation to obtain compen-
sation. The American Petroleum Institute and a number of major
oil companies support federal legislation to establish a spill
liability fund to provide such compensation.

RECOMMENDATIONS

43. INCREASE FEDERAL ENFORCEMENT AND MONITORING FUNDS.

Congress should increase the funds available to the U.S. Geo-

logical Survey in order that USGS can at least maintain existing

levels of enforcement of pollution control regulations as the

number of California OCS production facilities increases.

Congress should also continue support for the Coast Guard/NOAA

spill monitoring teams.

44. INCREASE SPILL CONTAINMENT BOOM STORED AT OFFSHORE

PLATFORMS. The State Lands Division and the U.S. Geological

Survey should requi're that at least 1,500 feet of heavy-duty

containment boom, and a boat suitable for deploying it,

be maintained at each production facility serving oil fields

off California. Where, by reason of geolraphic location or

prevailing winds and currents, potential spills from any parti-

cular field pose a direct threat to especially sensitive coastal

resources, such as estuaries, marshes or pinniped rookeries,

the containment boom requirements for that field should be

increased. For fields with several production platforms, the

boom and vessel should be kept at a central platform so the

equipment can be promptly delivered.to any of the platforms on

that field.

45. RELOCATE ONSHORE EQUIPMENT TO PROTECT SENSITIVE

NATURAL AREAS. The three southern California spill coopera-

tives should earmark a portion of their spill containment boom

to protect estuaries, salt marshes, and.other specific coastal

resources with both the high natural value and the restricted

connection to the ocean which makes such defense practicable.

This boom should.be sited so as to reduce to a practical mini-

mum the time needed to deploy it in diverting spilled oi.1 away

from the designated re*sources.

46. REQUIRE OIL SPILL CLEANUP ORGANIZATION INSPECTIONS

AND "FIRE DRILLS." Oil spill cleanup organizations should

be required to undergo annual inspections of personne'l train-

ing programs, response procedures, equipment inventories, and

equipment locations, and should be required to respond to

unannounced, in-water oil spill "fire drills" simulating emer-

gency spill conditions. These i-nspections and drills could be

implemented voluntarily by the industry, or as a condition of

federal, state, or local permits for oil-related facilities.

In order to avoid overlapping and perhaps conflicting demands

on the cleanup organizations relied upon by applicants for

federal, state, and local permits,, the Resources Agenc y would

be an appropriate place to vest authority for initiating-"fire

drill" emergency simulations and conducting annual inspections,

in consultation with interested federal and local agencies.

47. BRIEF LOCAL OFFICIALS AND INTERESTED PUBLIC ON SPILL

RESPONSE PROCEDURES. The California Department of Fish and

Game should conduct a series of workshops in the coastal

counties of southern California.to inform local officials and

the interested public of: a) the procedures followed by in-

dustry, federal, and state personnel responding to oil spills;

and, b) the responsibilities and opportunities for local

participation in oil spill cleanup operations within the con-

text of the national and state oil spill contingency plans.

48. JOINT STATE-LOCAL-INDUSTRY ACTION TO IMPROVE RESPONSE.

Each coastal county should, with the assistance of the Resources

Age.ncy and oil industry representatives, evaluate existing

procedures for responding to oil spills within its jurisdiction,

and develop its own contingency plan to make local resources

available to assist industry.and federal oil spill cleanup

efforts. As part of its planning, each county should: a) com-

pile-an inventory of publicly-owned equipment and personnel

potentially useful in spill cleanup operations; b) identify

access routes for delivering equipment to all coastal areas

within each county; c)@identify and rank specific coastal areas

vulnerable to and threatened by potential oil spills; and, d)

compare county protection priorities-with those of the industry

cooperatives responding to spills threatening those areas. As

a first step to improve protection of specific coastal re-

sources, county and local governments should consult with clean-

up organi.zations to assure that equipment is provided, earmarked,

or stored at locations suitable to assure the necessary pro-

tection. As a last resort, these governments should consider

purchasing and stockpiling containment-booms in

appropriate locations, and arranging for its deployment to

protect specific designated areas in an oil spill emergency.

49. RETAIN CONTROL OVER USE OF CHEMICAL DISPERSANTS.

Existing federal and state policy advocating the physical con-

tainment and recovery of spilled oil should be maintained,

spelling out the permitted use of chemical dispersants only in

extraordinary circumstances.

50. COLLECT WIND, WAVE, AND CURRENT DATA AT OFFSHORE

FACILITIES. The State Lands Division and the U.S. Geological

Survey should require that instruments suitab.le for measuring

and recording wave, surface current, and wind data be installed

and maintained on all offshore drilling, production, and ter-

minal facilities off California and that the data collected be

publicly available. Costs of purchase, installation, and main-

tenance should be borne by the operator of the facility. The

instrument specifications should be established by SLD and USGS

in consultation with the California Department of Navigation and

Ocean Development and the National Oceanic and Atmospheric

Administration, so that the data can be stored and retrieved

from existing state and federal oceanographic data systems
(e.g., California's Coastal Engineering Data Network and the

National Oceanographic Data Center). Where a facility is suf-

ficiently close to another, already instrumented, or to an

existing meteorological station, so that data already being

collected is substantially applicable, this provision should be

waived.

51. ESTABLISH AN OIL SPILL FIELD RESEARCH FUND. Congress

should.establish a $10 million field research fund to support

study of the short-term and long-term biological and ecological

effects of oil spills. When spills occur, the fund should be

used to employ qualified scientists undertaking chemical and

biological sampling and analyses in the affected area without

delay and for as long as necessary. Uniform sampling, survey-

ing, and analytical methods should be established bv the aqency

administering the fund.

52. SPILL COMPENSATION FUND. The state should establish

a spill liability compensation fund financed through a per-

barrel oil transfer fee.on oil transported across state tide-

lands to provide a source for private and public claimants to

obtain adequate redress for harms not now recognized as "legal

damages" and without the uncertainty and expense of protracted

litigation. If federal legislation is enacted adequately

assuring these objectives, the state fund should be phased out.

53. CIVIL LIABILITY. The state legislature shouldamend

.the Porter-Cologne Water Pollution Control Act to allow the

imposition of civil penalties for major oil spills in excess

of those now allowed under a restrictive interpretation of the

current legislation.

CHAPTER 8:

ECONOMIC EFFECTS
OF LEASE SALE #35

FINDINGS

PRE-LEASE SALE ESTIMATES ARE SPECULATIVE. Economic
analyses can become more precise as development unfolds. The
effects of exploration-phase employment and income depend on
the number of tracts actually leased, possibly only 20-30% of
those offered. The amount of oil or gas discovered on leased
tracts determines the employment impacts and facility needs
of the development and production phase. Local public service
demands are created by the settlement patterns of imported
workers, which may not correspond with the siting of facili-
ties and service bases. Actual tax impacts on any community
cannot be determined until the development phase, when parti-
cular facilities are proposed for specific Iocations.

ASSUMPTIONS ARE CRITICAL-. Conclusions concerning economic
impacts'are sensitive to assumptions about oil and gas reserves,
location of onshore facilities and construction sites, worker
residence patterns and ratios of local to imported labor.
Conclusions about economic impacts of Lease Sale #35 cannot be
validly transferred t'o describe the cumulative effect of sub-
sequent sales or the consequences of offshore development on
rural, less.densely populated areas of California with no
history of oil development and no local pool of skilled labor.

EMPLOYMENT AND PUBLIC SERVICE IMPACTS. The impacts of
Lease Sale #35 will be felt primarily in the adjacent counties
of Ventura, Los Angeles, and Orange. These impacts will be so
small that new direct and indirect employment will be insignif-
icant, with imperceptible increases in public service demand.
These conclusions would hold true even if the level of new OCS
activity were three times that currently anticipated.

PRICE IMPACTS. In Los Angeles and Orange counties,

*For full discussion, see Chapter 18.

short-term price increases for housing and consumer durables
will be inconsequential.. Price increases may approach 2% in
Ventura.

TAX IMPACT. New facilities inspired by Lease Sale #35
will constitute only a small fraction of the total assessed
valuation of each of the affected counties. In Los Angeles,
Orange, and Ventura counties, for example, net taxable base
is over $35 billion. Optimistic estimates of new facilities
from OCS Sale #35 are only $160 million, or less than 0.46%.
It is unlikely that any one county will get all of the
facilities. However, any municipality which is the site for
one or more of the facilities may realize a substantial tax
windfall which exceeds new se-rvice demands. Precise locations
for these facilities will not be known until late in the
development process.

ENVIRONMENTAL COSTS NOT COUNTED. Caution must be exer-
cised in assessing net local benefits from price, public
service, employment, and tax and transfer analyses alone. These
do not include environmental costs which may be substantial,
but for which there is no widely accepted measure of value.
The ultimate balancing of OCS economic benefits against poten-
tial environmental costs is a highly judgmental process.

PRICE OF OIL AND GAS. Production from OCS Lease Sale #35
will not affect the price paid by southern California consumers
for petroleum products or natural gas. New OCS gas may, how-
ever, partially alleviate projected gas shortages and reduce
costs and dislocation caused by switching to higher-cost
substitute fuels.

EFFECTS OF OTHER OFFSHORE ENERGY PROJECTS. This analysis
was limited to the economic effects of the exploration and
development of tracts leased in OCS Lease Sale #35. The
economic effects of other energy-related activities. offshore
or in the coastal zone (e.g., development on oil and gas
leases in the Santa Barbara Channel, future OCS leasing in
southern California, construction and operation of a liquid
natural gas (LNG) terminal, the proposed SOHIO project for
transporting Alaskan oil) were not examined in this study.
Consequently, the economic effects of these coastal-related
energy activities may, by themselves or in combination with
the effects of exploring and developing the tracts leased in
Lease Sale #35, have significant impacts on southern California.

RECOMMENDATION

54. DETAILED ANALYSIS AND COOPERATIVE PLANNING. When new

OCS development may substantially affect the structural rela-

tionships or overall volume of economic activity in an area,

the Department of the Interior should aid in the prepara-

tion of detailed site-specific analyses of these effects and

cooperate with local governments in identifying and planning

for public service expenditures necessitated by the develop-

ment. Such impacts are not expected in southern California

in the immediate future. Communities identified as most

likely to experience appreciable new development as a result

of Lease Sale #35 are Ventura, Port Hueneme and possibly

Huntington Beach.

CHAPTER 9:

FACILITIES PLANNING*

FINDINGS

POTENTIAL FOR DUPLICATION. The demands placed on existing
Offshore oil and gas rel@_t_ed facilities and the need for new
facilities in southern California will increase as develooment
activities accelerate in the Santa Barbara Channel and Lease
Sale #35 areas. There is a potential for unnecessary duplica-
tion of offshore production sYstems.and onshore sunDort facili-
ties. To limit the effects of offshore related oil and gas
operations, it may be desirable to renuire: (1) that area plans
be prepared for specified offshore leased areas; (2) that cer-
tain leases overlying geologic structures likely to contain oil
and gas be unitized; and, (3) that related onshore facilities be
consolidated.

LEASE-AREA PLANNING: COORDINATINn DEVELOPMENT OVER LARGE
OCS T-R-EAS. Offshore southern California leases have been acquired
in six separate geographic areas:

Santa Barbara Channel- West
Santa Barbara Channel East
Santa Rosa-Cortes Ridge-North
Santa Rosa-Cortes Ridge South (Tanner Banks)
Santa Barbara Island Offshore
San Pedro Bay

.Each,area has unioue resource develooment problems resulting
from its relative distance to shore, water depth, estimated
recoverable resources, and number of leases sold. The most effi-
cient-and environmentally safe solutions to these problems are
obtained when each area is planned for as a whole. Lease-area
planning also permits the sharing of develoi)ment risks and costs
by operators within the area and serves to maxi.mize the natural
resources of the outer continental shelf.

*For further discussion, see.Chapter 19.

UNITIZATION: COORDINATING DEVELOPMENT ON SPECIFIC.GEOLOGIC
.STRUCTURES. Unitization occurs when companies owning leases over-
Tying a single geologic structure merge ownership and control of
the area or structure through an agreement whereby a single company
or committee acts as the operator for exploration, development,
and/or production of all leases affected by the agreement. Uniti-
zation may be entered into voluntarily or it can be required by
the Geological Survey.

CONSOLIDATION: FOR COORDINATING DEVELOPMENT AND/OR UTILI-
ZATION OF SPECIFIC FACILITIES. Consolidation occurs when two or
more companies use the same site or facilities for development,
transportation, processing, or storage functions, rather than
each company constructing and operating such facilities solely
for its own needs.

CALIFORNIA COMMITTED TO COORDINATION.
State agencies have consistently pursued the coordination of off-
.Shore and onshore petroleum facilities since 1975. The California
coastal zone management program is the principal government mecha-
nism through which such coordination initiatives are advocated.
Local governments have demonstrated the same commitment through
such actions as the formation of the joint industry/government
working group investigating better ways of coordinating offshore
and onshore development in the Santa Barbara Channel.

RECOMMENDATIONS

55. CONSISTENCY WITH COASTAL ZONE MANAGEMENT PROGRAMS.

USGS, in cooperation with the California Coastal Commission,

should promulgate specific and detailed guidelines for achiev-

ing consistency of all OCS operations and facilities with state

and local coastal zone management programs. In California, the

USGS Pacific Area Supervisor should,require all operations and

fac.ilities related to offshore California OCS exploration and

production to be consistent with state and local consolidation

policies. The Pacific Area Supervisor should periodically reas-

sess the consolidation opportunities by performing an inventory

of existing facilities and their level of use, and re-examining OCS

production prospects and the Department of the Interior's leas-

ing schedule. USGS should solicit the.assistance of state and

local agencies in performing this periodic review.

56. INDUSTRY RESPONSIBIL ITIES. Industry must recognize its

responsibility to develop the OCS and all related facilities in.

a manner consistent with California's coastal zone management

program and the goals of state and local environmental planning

agencies. Because of its expertise, industry should take the

initiative in defining consolidation strategies designed to

minimize land use and environmental'impacts.

L E A S E - A R E A P L,A N N-1 N G

FINDINGS

AUTHORITY FOR LEASE-AREA PLANNING. Such authority is de-
rived from the OCS Lands Act which requires that "the Secretary
shall administer the provisions of this Act ... in order to pro-
vide for the prevention of waste and conservation of the natural
resources of the Outer Continental Shelf." The area supervisors
of the Geological Survey and the Bureau of Land Manaqement are
delegated some discretion in carrying out this mandate for the-
Secretary which would allow their initiation of such lease-area
plans. Precedent for lease-area planning has been set by Inter-
ior's commitment to pipeline corridor planning.

OBJECTIVES AND PRODUCTS OF LEASE-AREA PLANS. The objectives
of lease--;area planning are to coordinate development of potential
offshore resources in a qiven area, eliminate unnecessary dupli-
cation of essential faciiities, and eliminate uncertai'nties of
future development for each leased area. The prod ucts of a lease-
area plan would include timing parameters for exploration and
development, requirements for future unitization of leases within
the study area, clearly defined transportation and processing
options, and criteria for development approval agreed to by gov-
ernment and industry. Lease-area plans would be flexible enough to
accommodate the necessary and inevitable changes that come to light
as new-wells aredrilled and new information becomes available.

LEASE-AREA PLANNING TO EXPEDITE OFFSHORE DEVELOPMENT. Lease-
area plans would provide offshore operators with timing priorities
for each operator's exploration and/or development activities in a
given area. This would allow separate companies the opportunity
to share the use of,mobile drilling rigs, pipelayinq barges, heavy
construction equipment, or other costly operations by adjusting
their separate exploration and/or devel-opment schedules accordingly.
Lease-area plans would provide governmental agencies with timing
parameters for permit processing by all regulators involved in off-.
shore-related development. This would allow an.opportunity to
consolidate permit review and approval procedures, eliminating the
enormous duplication of effort and protracted time ordinarily
required for project approval. Lease-area plans would impose -timing
constraints on both industry and government, allowing each side to
determine how to make the most efficient use of its ovin and the
other's limited time and manpower.
C@-76658 67

RECOMMENDATION

57. LEASE-AREA PLANS SHOULD BE PREPARED JOINTLY BY INDUSTRY

AND GOVERNMENT. Lease-area plans for existing leased areas should

be undertaken jointly by representatives of companies holding

leases in the planning area, and representatives of affected

federal, state and local permitting agencies. Plans for proposed

lease areas should be undertaken jointly by representatives of

Western Oil and Gas Association, California Independent Producers
Association, and-affected permitting.agencies. Lead responsibility
for lease-area.plans should be in the office of the Secretary of

the Interior. When one operator is ready to commence development

before other operators are ready to participate in a lease-area

plan, then this lease-area plan requirement could be waived by the

Interior Department, providing that the objectives of lease-area

plans are incorporated in the initial plan of development.

U N I T I Z A T 1 0 N

FINDINGS

UNITIZATION: VOLUNTARY OR MANDATORY. When there is a clear
.econoFir-c-advantage to unitization, petroleum companies form units
voluntarily. USGS, however, has authority to require unitization
in the interests of conservation. The courts have liberally inter-
preted this-to imply the conservation of all natural resources,
including air, water, and marine life.

UNITIZATION'S NUMEROUS BENEFITS. It allows exploration and
development programs to be based on the-nature of the oil and
gas prospects, rather than on lease boundaries and ownership
considerations, which.are basically irrelevant to the task of
locating and recovering commercial deposits of oil and gas.
Unitization increases overall recovery from reservoirs by per-
mitting use of the most efficient "natural drive" and sec-
ondary recovery methods not otherwise available in some types
of competitive practices. Unitization also eliminates many
costs and faciliti&s, resulting in:

1) financial savings to companies;

2) environmental/land use savings to onshore communities;

3) fewer administrative permits, with savings both to
companies and to communities; and,

4) accelerated developnent of oil and gas resources.

TIMING OF UNITizATION. Unitization occurs most often after
initial exploration has begun and discoveries have been made.
Where unitization has occurred prior to exploration, industry
motivation has been to retain leases beyond their initial five-
year term.

INDUSTRY SUPPORTS VOLUNTARY UNITIZATION. Unitization of
leases overlying a competitive reservoir is actively sought by
many petroleum companies because it saves costs and achieves an
equitable arrangement for the recovery of petroleum resources.
Voluntary unitization allows the petroleum companies greater
freedom of choice in what, when, and with whom they unitize.

INTERIOR RECOMMENDED MANDATORY UNITIZATION. A Department
of Interior staff analysis performed in 1975 recommended that
DOI pursue mandatory unitization of frontier areas, includinq
the southern California Outer Banks. The staff report also
recommended that DOI consider mandatory unitization of leases
already sold in the Santa Barbara Channel.

DISADVANTAGES OF MANDATORY UNITIZATION. Mandatory uniti-
zation would offer California the advantages of accelerated
development already noted, but it would also narrow industry's
flexibility in making investment decisions. As a condition of
future lease sales, it might reduce speculative bids by indus-
try and thus lower lease sale revenues. Industry contends that
in some instances mandatory unitization could prolong explora-
tion and impede efficient development.

ABUSE OF UNITIZATION. Unitization may be employed as a
lease-holding device, effectively delaying rapid expl'oration
and development of OCS resources. OCS regulations provide for
the extension of the primary term for unitized leased tracts
if "diligent and good faith" efforts are being made to explore
and/or develop any one tract in the unit. This privilege has
extended the lease-term of four tracts in the Santa Ynez Unit
which have never been directly explored.

POTENTIAL NEW UNITS OFFSHORE OF CALIFORNIA. If mandatory
unitization were required, it would affect leased tracts in
the Outer Banks and San Pedro Bay and the Santa Barbara Channel
leases sold in 1968. There are 20 non-unitized leases in the
Channel located in four different areas.

COMMON OWNERSHIP MAY OBVIATE UNITIZATION. Where all tracts
leased over a complete geologic structure are held by a single

company or single consortium of companies, the coals of uniti-
zation are effectively satisfied. Unitization serves little
purpose in these instances other than to extend the primary
term of leases within the unit boundary. Examples of tracts
leased over a complete geologic structure held by a single
company or single consortium of companies include the San
Miguel Unit and the proposed Santa Cruz Unit in the Santa
Barbara Channel.

RECOMMENDATIONS

58. UNITIZATION OF NEW LEASES. USGS should require uniti-

zation of all leases sold in Lease Sale #35, according to common

geologic structures which they overlay except thos e contained

within a single lease or group- of leases held in common ownership,

and of all potential leases that could be-sold as a result of lease

Sales #48 and #53 with the same exception. One plan for mandatory

unitization is outlined in Appendix A of Chapter 19. Un i.ti-

zation of the remaining non-unitized leased tracts in the Santa

Barbara Channel is not recommended at this time because these

groups are held in common ownership.

59. STATE AND LOCAL GOVERNMENT INVOLVEMENT. The Interior

Department should institute procedures for involving state and

local governments in unitization decisions to the extent that

they affect onshore land use decisions and regional energy supply

issues. It is not the intention of this recommendation to sub-

ordinate national energy policy to state or local interests.

C 0 N S 0 L I D A T 1 0 N

FINDINGS

CONSOLIDATION'S NUMEROUS BENEFITS. Consolidati.on of sites
and facilities offers most of the same advantages offered by
unitization. In addition, consolidation reduces:

a. industrial land reauirements near the coastline,

b. conflict,with other coastal land uses,

c. the number of potential sources of oil spill and air
pollution,

d. the amount of energy and raw materials used in con-
struction and operation of the facilities,

e. the costs of facility operations, and,

f. adverse scenic'effect of additional industrial facili-
ties in coastal areas.

EXISTING POLICIES FOR CONSOLIDATION. Express policie's of
California's coastal zone manaqement program (see California
Coastal Act of 1976) and Santa Barbara County require that
facilities related to offshore petroleum exploration and pro-
duction be consolidated wherever feasible..

CONSOLIDATION RARE IN CALIFORNIA. In the past, industry
has consolidated facilities when operating economies have been
apparent. Generally, however, companies operating off the
California coast have preferred to construct and operate their
own facilities in order to maximize flexibility in production
and marketing strategies. Historically this has resulted in a
proliferation of offshore pipelines, small onshore oil and gas
processing plants, and tanker terminals alonq the coastlines of
Santa Barbara and Ventura County and between Long Beach and
Huntington Beach.

INDUSTRY RESISTANCE TO CONSOLIDATION STRATEGY. Industry
opposition to consolidation is variously based on contentions
that:

a. indiscriminate application of consolidation strategies
would increase capital costs prohibitively, especially
for small-scale operations;

b. the information exchange and inter-company cooperation
that must attend planning for and operation of consoli-
dated facilities may lead to a loss of competitive ad-
vantage and violation of antitrust laws;

c. the uncertainty of information regarding recoverable
reserves, production rates, and timing of production
restricts the precision with which consolidated facili-
ties can be planned;

d. a company's flexibility in production and marketing
strategies will be impaired by facilities that must
be-designed and operated to meet the needs of other
companies; and,

e. physical properties of oil and gas produced from
different reservoirs would contaminate each other.

NO LOSS OF PATENTS OR PROPRIETARY INFORMATION. The inter-
company cooperation required for consolidation of facilities
related to offshore petroleum has not jeopardized technical
patents and proprietary information in facilities already con-
solidated.

NO CAUSE FOR ANTITRUST VIOLATION. When public agencies
require petroleum companies to consolidate facilities for
environmental or other public policy reasons, inter-company
planning efforts necessary to construct and operate the
facility are not in violation of antitrust law, absent a show-
.ing of intent to act in restraint of trade.

CONSOLIDATION NOT PRECLUDED BY VARIANT CRUDE CHARACTER-
ISTICS. There'are no physical properties of offshore petroleum
resources that prevent commingling. The commingling of crudes
can occur at any point between recovery at production stations
and eventual delivery via tanker or pipeline to a refinery.
With limited exceptions, the combination of crudes differing as
to gravity, sulfur content, or viscosity always results in
averaging of respective characteristics in proportion to the
constituent volumes mixed. The main consequence of com-
mingling one crude oil with others will' be to affect its
marketability, which varies according to the demand for the
crude derived. If crude oils are to be commingled, pro-
ducers prefer to do so after by-products and wastes have been
separated, making it easier to compute the value of their
respective marketable crudes and the amount of royalty they
must pay.

THE TIMING COMPLICATION. Inter-company planning for con-
solidated facilities is complicated by the great latitude lease-
holders are allowed in proceeding toward development. Under
existing laws and regulations, a lessee is oermitted five years
following a lease sale to take significant steps toward develop-
ment. Unitization can extend this period further for some leases.
Successful bidders proceed with exploratory activity on widely
,.variant schedules, depending on.

a. the amount of capital invested in the lease purchase,

b. the prospects for petroleum recovery,

c. the success of initial exploratory wells, and,

d. internal company investment decisions.

Within a geographic area leased in a single sale, acquisition of
resource information and development decisions of individual
companies may be spread over a five- to ten-year period.

ENVIRONMENTAL "HOTSPOTS." In some instances, consolidation
of facilities may raise environmental problems more serious than
those it solves. The increased activities at a single site could,

for example, exceed point source air pollution standards which
miOht not otherwise occur if several smaller dispersed facili-
ties were utilized.

D'IFFICULTIES OF ECONOMIC ANALYSIS. Economic analysis. of
consolidation options by public decision makers is complicated
by:

a. incomplete information about the producible petroleum
resource;

b. incomplete information regarding the capital invest-
ment and marketing strategies of individual companies
involved; and,

c. inadequate analytical tools for measuring the economic
value to society of environmental improvement mitiga-
tion of adverse environmental effects, or eli@ination
of the risks of environmental damage.

RECOMMENDATIONS

60. NEED FOR A FEDERAL POLICY. USGS should adopt a policy

in clear and explicit terms that requires consolidation of trans-

portation, storage, treatmenti.and service facilities related to

OCS exploration and development where feasible and unless there

are strong economic or environmental reasons consolidation is-

not desirable. USGS should promulgate explicit regulations to

effect this policy for existing leases. BLM should incorporate

a consolidation policy in lease stipulations for future lease

sales.

61. FEDERAL ROLE IN CONSOLIDATION. Any EIS and other

reviews of any development plans should include detailed con-

sideration of possibilities for consolidating crude oil trans-

portation, storage, and.treatment operations of the develop-

ment area in question with similar operations occurring in the

same geographi-c area and time frame. Discussion of consolida-

tion opportunities should include detafled accounts of economic,

timing, engineering, and environmental issues. Such analyses

Will require the cooperative efforts of the Department of the

Interior and state and local agencies to resolve jurisdictional

problems.

CHAPTER 10:

TRANSPORTATION*

FINDINGS

General-

TWO PHASES OF TRANSPORTATION. Offshore oil and gas is
transported:

a. between the production platform and the processing
facility, where emulsified or associated oil, gas, and
water are separated and treated; and,

b. between the processing facility and refinery or gas
company transmission system.

Transportation options are tankers, barges., or pipelines for
crude oil, and pipelines or liquefied natural gas (LNG) carriers
for natural gas. 'All crude oil and natural gas presently
produced in southern California are transported by pipelines to
processing facili,ties; crude oil is then either pipelined or
tankered to refineries, and natural gas is pipelined to gas
company transmission lines.

PIPELINE ROUTING DECISIONS. Pipeline developers seek the
route providing the best combination of lease distance, shal-
lowest water depth, and avoidance of geologic hazards. In the
Santa Barbara Channel and San Pedro Bay, the shortest routes
from oil and gas fields to shore are also the shallowest. In
the outer banks, the shortest routes encounter impractical
water depths and the optimum pipeline route thus involves
substantially longer distances than a direct route to shore.

TANKER ROUTING DECISIONS. Optimum tanker or barge routing
requires the shortest navigational course consistent with
navigational safety. All southern California coastal traffic
passes through Santa Barbara Channel and San Pedro Bay 1,eased
areas.

*For further discussion, see Chapter 20.

ECONOMIC DETERMINANTS OF OIL AND GAS TRANSPORTATION MODES.
The major economic determinants for a crude oil transport system
between offshore producing areas and onshore facilities are:

a. size and projected life of the oil field;

b. market value of the oil and gas;

c. rate of production;

d. amount of capital investment required for development;

e. distance from the field to the receiving point on land;

f. operating costs of the system;

g. water depths; and,

h. topography of the ocean floor.

DESTINATION OF SOUTHERN CALIFORNIA OFFSHORE OIL AND GAS.
All natural gas produced off southern California is consumed
in southern California. The distribution of offshore crude
oil is less certain, but it is estimated that over 80% is
refined and consumed in the Los Angeles Basin. The distribu-
tion of offshore production depends in part on the availability
of transportation systems but is more sensitive to market
demands and government regulations.

Crude Oil Transportation

OIL CHARACTERISTICS AS DETERMINANTS OF TRANSPORTATION
MODES. The characteristics of California crude oils do not,
in general, dictate the transportation mode used. Instead,
they impose design or operational constraints on whichever
mode the operator selects. The properties of crude oil signi-
ficant in pipeline design are viscosity and speci.fic gravity.
Viscosity of the oil governs the pipe dimensions, which in
turn establish-the material and laying costs and fix the size
and number of pumping stations. Viscosity and specific
gravity together determine the energy required to pump the
crude oil.

SULFUR AS A DETERMINANT OF CRUDE OIL TRANSPORTATION.
Sulfur content may affect the design of a transportation
system. Sulfur compounds are undesirable in oil and must be
reduced to acceptable levels for a refinery; hence, the
choice of destinations for the crude is limited by refinery
desulfurization capabilities. Of more importance to the
selection of a transportation mode is the amount of hydrogen
sulfide gas (H2S) in crude oil. Crude oil high in sulfur is
referred to as "sour" and can be corrosive when combined
with water. Platform treatment can reduce H2S in oil (or
natural gas) to levels acceptable for pipeline transshipment,

but further 'Istripping" at a processing plant is required be-
fore shipping companies will accept sour crude for transport
by tanker. A pipeline system can be designed and operated to
transport commingled high sulfur and low sulfur oil without
"batching" (moving.separate quantities of oil in alternating
intervals)..

PRODUCING AREA TO PROCESSING SITE. Processing plants
are located as close as possible to production areas to
reduce transportation costs. The costs of transporting unpro-
cdssed crude oil by tanker to processing sites is normally
prohibitive because the purchaser would be paying for shipment
of emulsified waste water and other impurities as well as the
crude oil. Where the transportation costs become too high, or
if onshore processing facilities are unavailable, oil producers
have proposed offshore processing plants, with the transship-
ment of the processed crude to refineries by tanker (see, for
example, Santa Ynez Unit and Santa Clara Unit development
proposals). Such offshore alternatives remain undesirable for
OCS development off the.southern California coastline
because.they increase the risks of oil spills entering the
marine environment. Navigational safety is also impaired by
additional unnecessary fixed structures in the OCS.

PROCESSING PLANT TO REFINERY. Fluctuations in crude oil
production and demand argue for flexible delivery systems
between processing.plants and refineries. Under ideal condi-
tions, both producer and refiner prefer a pipeline network.
Direct pipelines are preferable because the throughput can be
regulated, thereby avoiding the use of tankers and eliminating
tanker-rel.ated storage requirements at the processing end. A
pipeline network can also link several processing plants with
one or more refineries to allow selective delivery of differ-
ent crudes or blends of crude as market demand requires.
Refineries are always located close to market areas because
of higher transportation costs past the refining stage.

COSTS OF CONSTRUCTING CRUDE OIL PIPELINES. Based on
actual costs of existing onshore pipelines, the cost of line
pipe and installation labor usually constitutes over 70% of
the investment required to construct an onshore pipeline.
Other average costs for onshore pipelines are land (.3%),
right-of-way (2.3%), pipe fittings (2.5%), buildings (2.8%),
pumping equipment (6.7%), other station equipment (8.7%),
storage tanks (5,.2%), delivery facilities (.7%), and miscel-
laneous appurtenances (1.3%). Estimates for onshore pipe-
line costs in southern California may differ slightly from
these estimates where highly urbanized areas are encountered.
Offshore pieplines cost twice to ten times as much as same-
diameter onshore pipelines, depending on the length required
and water depths encountered. The primary difference is in
installation costs which are proportionately much higher for
offshore pipelines.

Natural Gas Transportation

. PRODUCTION SITE TO PROCESSING PLANT. All natural gas
produced offshore must be transported by pipeline from produc-
tion sites to processing plants for treatment and separation.
Where processing sites are not available or the quantities of
gas produced are too small to justify a pipeline, natural gas
is typically flared or reinjected into the underlying geology
(flaring is not permitted off southern California). Offshore
processing of natural gas discoveries in southern California
waters has not proven economically feasible under current
technology.

PROCESSING SITE TO GAS COMPANY: PIPELINES VS. LNG.
Liquefied natural gas LNG operations have been developed for
large natural gas fields separated by thousands of miles
from potential customers. Southern California OCS
leases are.not "remote," given this context, nor are the
expected quantities of natural gas of a scope to justify the
costs of such an operation. LNG also offers undesirable
risks, especially when compared to pipeline trans-
port. Pipeline routes from all leased areas off southern
California to mainland-gas company transmission lines appear
to be within reach of pipeline technology projected to be
available in the next five years.

Pipelines and Pipelaying

FLEXIBILITY IN PIPELINE CAPACITY. The throughput, or
capacity, of an existing natural gas or crude oil pipeline is
limited to the maximum allowable working stress of the pipe-
line walls, fittings, and valves but can be increased in some
instances by replacing an existing pump with a larger one, or
by adding new pump's on the line. Throughput of crude oil pipe-
lines may vary depending on the viscosity of crude oil shipped
in them: heating more viscous crudes will permit an increase
.in throughput over non-heated systems. An operator can pro-
vide for flexibility in a new pipeline's capacity, even with
@an unknown production rate, by designing the line for the
highest anticipated throughput,,but with a provision for adding
more pumping units as required. For example, a 36-inch crude
oil pipeline once proposed by Socal between Estero Bay and
Richmond was designated to accommodate throughput rates of
340,000, 420,000, or 570,000 barrels of oil per day, depending
on whether two, four, or five pumping stations were put into
operation.

PIPELAYING CAPABILITY. Water depth is a principal limit-
ing factor to offshore pipeline transportation systems. The
maximum depth of pipelines currently in operation is 600 feet
in the North Sea, but this will be increased to 850 feet-when
Exxon completes Platform Hondo in the Santa Barbara Channel.
Experimental pipelines have been installed at depths of 1,000
and 1,200 feet, and a pipelaying ship designed with a capabil-
ity of laying a 24-inch diameter pipe at a 3,000-foot depth is

due to be launched in 1977. The trend of recent developments
in pipelaying equipment and the goals being set by industry-
sponsored research programs indicate that all leased areas off
southern California can be serviced by on-bottom pipelines
within five years.

WATER DEPTHS AND PIPELINE ROUTES. The greatest dep th
encountered by any present lease off southern California is
2,500 feet (only one lease encounters this depth). Gathering
lines between all leases and central gathering stations of
leased areas would not encounter greater depths. Gathering
stations in the Outer Bank areas can be located in water depths
less than 850 feet for all OCS lease areas, and trunklines
connecting these gathering stations with the mainland can avoid
depths greater than 1,600 feet.

CALIFORNIA'S ONSHORE CRUDE OIL PIPELINE SYSTEM. Little
is known of the crude oil pipeline network in California: no
public agency has mapped all the crude oil pipelines, let
alone determined their ownership, current throughput, surplus
capacities, costs, or conditions of use. some information
has become available in these areas as a result of the efforts
of industry and government working together in the Santa
Barbara Channel area.

THE MAJOR PIPELINE CORRIDORS. Six major pipeline corri-
dors control the flow of crude oil-in California:

a. the lower San Joaquin Valley to Los Angeles Basin;

b. the Valley to the San Francisco Bay region;

c. the Ventura area to the Los Angeles Basin;

d. a highly integrated and complex network (over 1,000
separate pipelines) in the Los Angeles Basin moving
crude delivered from the San Joaquin Valley, Ventura,
Los Angeles and Long Beach Harbors, and local pro-
duction to the various refineries in the basin;

e. Central Califor ni-a Coast (Estero Bay and Avila Beach)
to the San Joaquin Valley, permitting shipment to or
from the coast and to the Bay region from Estero Bay;
and,

f. the Four Corners Pipeline, the o nly designated
common carrier line in California, linking the Los
Angeles Basin and the Four Corners area.

In addition, at each producing area there are numerous gathering
lines connected to the main trunklines. A surplus capacity of
216,000 B/D could be achieved in lines running from the San
Joaquin Valley to Los Angeles and the Bay Area with additional
heating stations and pumps.

CALIFORHIA'S ONSHORE PIPELINES ARE PRIVATE. Crude oil
pipelines offshore are common carriers if they cross unleased
federal submerged lands. Once crude oil is brought ashore, it
is delivered to refinery centers by either pipelines or tankers.
California is exceptional among oil producing states in that
all but one of the onshore crude oil pipelines in the state
are privately owned and nearly all are operated by major, in-
tegrated companies. Crude oil carried in these pipelines,
however, is not necessarily produced by the parent company
owning the lines, nor-is it used in that company's refineries.
Essentially these pipelines are operated like common carriers,
but the pipeline company "purchases" the crude oil from the
producing company at one end of the line, carries it to the
other end, and then resells it (possibly to the initial owner
or to a competitor). Operators of private pipelines thereby
avoid common carrier status in that they transport their "own"
crude oil. This poses certain limitations on the flow of off-
shore crude oil or any crude oil in that private pipeline
owners regulate the costs of the crude oil moving through them
and can control access as well.

COMMON CARRIER VS. PRIVATE CRUDE OIL PIPELINES. The
major oil companies in California prefer private ownership of
crude oil pipelines because it gives them an added measure of
control over crude oil marketing. Transportation costs
charged by common carrier oil pipeline companies are regulated
by the Interstate Commerce Commission (ICC). Tariffs for
privately owned crude oil pipelines are not regulated, allowing
the pipeline company to set its own price for purchasing crude
and reselling it. In 1974, the Joint Committee on Public
Domain of the California State Legislature recommended that
private carrier pir.elines he reoulated or controlled as common
carriers to allow access to all producers, and to insure a
competitive crude oil market.,

SOUTHERN CALIFORNIA'S ACCESSIBLE ONSHORE NATURAL GAS
PIPELINE SYSTEM. Natural gas pipelines are regulated by the
State PubTTc-Utilities Commission and are well documented.
Several natural gas companies serve the southern California
coastline from Point Conception to San Diego. Natural gas
transmission and trunk lines are within two miles of any land-
fall between Point Conception and the Mexican border. Engineer-
ing feasibility studies may be required before OCS natural gas
could be transshipped through these lines. Many of these gas
lines have the capacity to carry OCS natural gas production
Although new connecting pipelines may be required in some areas.

Marine Transport: Tankers and Barges

MARINE TRANSPORT USED WHEN PIPELINES NOT AVAILABLE.
Crude oil produced from the Long Beach-to-Huntington Beach
offshore area is delivered to Los Angeles refineries by pipe-
line, while crude oil produced from the Santa Barbara Channel
is delivered to refineries by pipelines and tankers. Tankers
are used between the Channel producing areas and Los Angeles
because existing pipelines are used to capacity. Tankers

are used between the Channel and Bay area refineries because
the two areas are not now linked by pipeline.

ENVIRONMENTAL RISKS: TANKER VS. PIPELINE. Every study
of transportation alternatives for southern California OCS
production to date has concluded that pipelines are safer to
use than tankers or barges. The volume of oil projected to
enter the marine environment as a result of tanker and barge
casualties and transfer operations is significantly greater
than the volume of oil expected from pipel'ine accidents. The
spill factor for tankers is almost seven times greater than
that for pipelines. Marine terminals also are undesirable
from an air quality standpoint. Emissions resulting from
tanker loading operations are the largest source of air pollu-
tion resulting from oil and gas development.

VESSEL TRAFFIC PATTERNS IN SOUTHERN CALIFORNIA. The
majority of foreign and domestic merchant vessel traffic in
southern California is confined to legally established
vessel traffic lanes from Point Conception to south of the
Los Angeles and Long Beach Harbors complex. Estimates for
the number of vessels per day in these lanes are:

Northbound Southbound

Offshore of Point Arguello 7.3/day 8.2/day

Between Pt. Conception and
Port Hueneme 6.6/day 6.0/day

Between Port.Hueneme and
LA/LB Harbors 12/day 10.6/day

Between LA/LB Harbors and
Canal Zone 5/day 3.5/day

Crude oil and product tanker movements to and from the five
active marine terminals in the Channel, the.four marine ter-
minals at El Segundo, and the one marine terminal at Huntington
Beach are included in these traffic estimates. Tankers
,originating in Los Angeles or Long Beach Harbors or El
Segundo move through-the northbound lane to the Channel,
leave the lane to make several calls at the Channel marine
terminals, and return by way of the southbound lane to the
Harbors or El Segundo for offloading.

PROJECTED VESSEL TRAFFIC INCREASES CAUSED BY SOUTHERN
CALIFORNIA OFFSHORE CRUDE OIL PRODUCTION. If an onshore
pipeline is not constructed to deliver Santa Barbara Channel
production, as many as 40 new roundtrips per month can be
expected by 1980. New production from South Elwood,,Summerland,
and Carpinteria offshore fields could add seven roundtrips per

month; the Santa Ynez Unit could add 11 round trips per month;
new production from Platforms C and Henry could add five round
trips per month from the Union marine terminal at Ventura; and
new production from the Santa Clara and Hueneme Units could
add ten round trips per month. Since the peak round trip esti-
mates occur at different times between 1979 and 1983, they
do not add up to the estimated total of 40 round trips projected
to occur in 1980. If pipeline options are not constructed for
the Outer Banks areas, an additional 40 round trips per month
for all three areas could occur in 1983.

NAVIGATIONAL SAFETY: POTENTIAL FOR COLLISION OR RAMMINGS.
The potential exists for a collision or ramming between OCS
exploration or production structures and passenger, cargo, or
tank ships. The Coast Guard has established the voluntary Vessel
Traffic Separation Scheme (VTSS) from Point Conception to south
of San Pedro Bay. Most commercial vessels operating off the
southern California coast use these lanes. In the Santa Barbara
Channel, 20 of the 65 active leases are intersected by the
designated shipping lanes; and seven of the thirteen federal OCS
leases in San Pedro Bay are either within these traffic lanes
or the adjacent separation and buffer zone. In 1976, the U.S.
Coast Guard recorded an average five vessels per day inbound
and 3.5 vessels per day outbound from Los Angeles/Long Beach
Harbors in the lanes. These estimates refer to passenger or
cargo vessels, tankers, sea-going barges, and Navy vessels with
drafts more than 18 feet; they do not include smaller barges,
commercial or sport fishing boats, pleasure boats, tugs,
research vessels, Coast Guard vessels, or the Catalina ferry.
Six hundred small vessels traverse the waters between Los
Angeles and Santa Catalina daily, creating problems of traffic
congestion in this area. Much controversy has focused on the
permits issued for structures to be positioned in or near the
Vessel Traffic Separation Scheme. It is the responsibility of
the Corps of Engi-neers (COE) to prevent obstructions to navi-
gation and to issue permits for fixed structures in navigable
waters. The COE has promulgated proposed guidelines, appli-
cable only to exploratory vessels in the Gulf of Santa
Catalina VTSS.

PROJECTED VESSEL TRAFFIC INCREASES CAUSED BY ELK HILLS
OIL, ALASKAN OIL, AND LNG ALASKAN AND/OR INDONESIAN).
Increased tanker traffic caused by these sources and the
traffic areas affected depends on final destinations approved
for each proposal. If a major crude oil port and/or LNG ter-
minal is constructed north of Point Conception, no increases
should be experienced to the south. If Sohio's Alaskan crude
oil terminal is constructed in Long Beach Harbor, all of the
Long Beach-bound Alaskan tanker fleet will pass through the
Channel en route to Long Beach or Valdez. If an LNG terminal
is constructed at Oxnard, all LNG deliveries from either
Alaska or Indonesia will be by way of the Channel. If an1NG
terminal is constructed at Point Conception, the Channel will
not experience increased vessel traffic from LNG tankers.

If the Elk Hills production is delivered to Port Hueneme,
vessel traffic in either direction will experience an increase.
The maximum projected traffic volumes for these sources follows:

Round Trips
Source Per Day

Crude oil from Valdez to assumes 1,200,000
Long Beach 1.1 B/D and-mean tanker
size of 136,825

Elk Hills oil from Port assumes 200,000 B/D
Hueneme to LA/LB Harbors and average tanker
or San Francisco 1.3 size of 35,000 DWT

LNG from Alaska and assumes each facility
Indonesia to Point is operating at de-
Conception, LA/LB, sign capacity of 4
and Oxnard 3.5 4.6 billion cubic feet
per day

RECOMMENDATIONS

62. PIPELINES VS. TANKERS. The State of California should

require the development of an efficient, common carrier crude

oil pipeline network linking all offshore producing areas with

California refining centers and west coast to mid-continent-pipe-
line systems, if developed. "It should be the policy of the state

that pipelines are preferred to tankersAn all cases, but that

current or future use of tankers or barges may be acceptable as

an interim solution while feasibility studies of pipeline corri-

dors (described in Chapter 11) are carried out and evaluated.

If crude oil pipelines prove-to be unfeasible or environmentally

.more damaging than tankers, the use of tankers-or barges shou1d-

be permitted for the life of the producing area.

63. NO FIXED STRUCTURES IN-TRAFFIC LANES. The Corps.-of

Engineers should revise and broaden its proposed guide.li.nes to

exclude all fixed structures associated with exploratory and

production activities from the lanes of the Vessel Traffic

7-76658 83

Separation Scheme (VTSS) in the Gulf of Santa Catalina and the

Santa Barbara Channel. Areas beneath the lanes may be explored

from vessels outside of the VTSS with slant drilling techniques

commonly used on production platforms and islands. Production

of areas beneath the lanes may be from surface structures

located outside the lanes or by ocean floor production systems

beneath the lanes. Ocean floor production systems, where feasi-

ble, are preferred to surface structures in either case. If

ocean floor production systems must be used, production wells

may be-drilled from surface vessels within the VTSS after

appropriate precautions have been completed.

CHAPTER 11:

DEVELOPMENT SCENARIOS

SANTA BARBARA CHAN WEL

FINDINGS

TIDELANDS OPERATIONS IN DECLINE. Most of the oil and gas
fields in state waters are approaching the end of their produc-
tive lifetimes. There are more than 20 processing and terminal
facilities supporting these tidelands fields. These facilities
range in age from ten to 40 years, and nearly all are operating
substantially below capacity. Many are obsolete.
Some will be abandoned in the near future, while others may re-
main economically viable for. 20 years or more. Most of these
facilities are well maintained, but many contrast sharply with
the surrounding environment, and some are a blight on the
landscape.

EXISTING PRODUCTION. There are two Santa Barbara Channel
OCS oil fields already in production: Dos Cuadras and Carpin-
teria. These two'fields combined now produce ahout 40,000 B/D
oil and 15,000 MCF/D natural gas.

SURGE OF ACTIVITY EXPECTED. Seven other oil and gas fields
have been found so far in the Channel OCS leases sold in 1968.
In ordinary circumstances, several of these fields would be in
production by now, but after the. 1969 blowout, the Interior De-
partment restricted drilling and production activities. With
the release in 1976 of an environmental impact statement on
Santa Barbara Channel oil and gas development, the Interior De-
partment is moving to allow operators to resume "normal" devel-
opment. With the removal of these restrictions a surge of
development activities in the Channel can be expected.

APPROVED, PROPOSED, AND POTENTIAL DEVELOPMENT PLANS. Devel-
opment plans calling for the installation of new platforms in the
Hondo and Dos Cuadras fields have been approved by the U.S. Geological

*For further discussion, see Chapters 14 and 21.

Survey. Three other development plans have been submitted to
USGS and are now pending. Four other discoveries have been
made in the Channel OCS, and their development feasibility is
now being evaluated.

OCS PRODUCTION WILL RISE SHARPLY. As these new fields
are developed, Channel OCS production will rise to more than
100,000 B/D oil and 100,000 MCF/D natural gas in the early
1980s. Total Channel production (state and federal leases)
could reach 200,000 B/D oil and 200,000 MCF/D natural gas in
the mid-1980s. Between 1976 and 2000, at least 700 MM barrels
oil and 850 BCF natural gas could be produced from existing
Channel OCS discoveries alone.

ADDITIONAL DISCOVERIES POSSIBLE. Exploratory wells have
been drilled on only 35 of the 65 existing Channel OCS leases.
Only 19 of these 35 leases have been explored with more than
one well. New discoveries could be made on any of the leases
currently without discoveries. Moreover, less than half of
the Channel OCS available for leasinq is now actually leased.
Nearly all of the unleased Channel OCS tracts are included in
proposed Lease Sale #48.

PEAK PRODUCTION IN 1980s. Channel-wide production from
existing discoveries will peak in the 1980s and decline there-
after. If new fields are found, their production is likely
merely to slow the overall decline following the 1980s peak,
rather than push Channel-wide production to new peaks in the
1990s. The facilities required for the development of the exist-
ing Channel discoveries may suffice to accommodate all future
Channel discoveries as well.

LAST CHANCE FOR CHANNEL-WIDE PLANNING. The development
proposals now being submitted will set the pattern for,all
future Santa Barbara Channel oil and gas development. The
opportunity,exists to program this development to meet Channel-
wide requirements rather than the exclusive needs of individual
companies. Given the status of Santa Barbara Channel oil and
gas development, this is likely to be the last such opportunity.

RECOMMENDATIONS

64. DETERMINE FUTURE NEED FOR EXISTING FACILITIES. The

State Lands Commission should determine probable remaining

lifetimes for all state tideland operations (marine terminals,
platforms, artificial islands, ocean floor wells, pipelines)

and their related onshore components (storage areas, processing
plants, service facilities) to assist local planners and operators

in preparing re-use plans for sites capable of being recycled.

Where public uses are anticipated, re-use planning can determine

,appropriate means of conveying title to the property from industry,

to a public entity. If a site is to be recycled for public use,

landscape treatment of the site to achieve mature planting appro-

priate to the intended purpose should be carried through in,advance,

of the change in use.

65. TWO PROCESSING P LANTS SUFFICIENT. All new Channel OCS

production should be accommodated at two processing plants: -the

existing Mobil-Rincon facility, desiqned for 95,000 B/D oil and

60,000 MCF/D gas, and the proposed Exxon-Las Flores facility

designed for 80,000 B/D oil and 90,000 MCF/D gas. These two

plants could process the levels of.production projected for all

known oil and gas fields in the Channel and could be expanded to

accommodate production from future discoveries in the Channel OCS.

66. PROCESSING OPTIONS AVAILABLE. As an alternative to con-

soli,dating all of the eastern Channel processing at Mobil-Rincon,

new production could be distributed among the existing Chevron-

Carpinteria, Phillips-La Conchita, and Mobil-Rincon processing

plants. This alternative may be preferable if the net regional

air quality impact resulting from these three point sources is

no greater than the impact resulting from concentrating all pro-

cessing requirements at Mobil-Rincon alone for the same throughput.

67. EASTERN CHANNEL OFFSHORE PIPEL.INE NETWORK. Operators in

the eastern@end of the Channel should devise a pipeline network

that:

a. minimizes the average length and number of pipelines

required to brinq natural aas and crude oil to shore; and,

b. provides access to and capacity for maximum anticipated

production from all east Channel leases.

,The network could consist of at least two trunk line corridors, the

already existing one originating at the Dos Cuadras field and the

other, tentatively being considered by Mobil and Chevron, originating

at the Hueneme Offshore field. (See Recommendations 10 and 12 of

this Chapter.) A third co'rridor may be required to serve the

proposed Santa Cruz Unit, the Oak Ridge Unit, and the Pitas Point

Unit. This pipeline should connect these three potential areas

with Mobil-Rincon via the existing pipelines between the Dos Cuadras

field and Mobil-Rincon or by a new direct route.

68. @WESTERN CHANNEL OFFSHORE PIPELINE NETWORK. If the exist-

'ing leases to the north of San Miguel and Santa Rosa Islands prove

to contain economically reco.verable petroleum resources and are

permitted to develop, these areas should be connected by pipelines

to the Santa Ynez Unit processing plant site. Connecting pipelines

between Santa Ynez production facilities should be designed to

accommodate any increased throughput that could result from the

leases near San Miguel and Santa Rosa Islands.

69. ONSHORE PIPELINE STRATEGY. Once ashore, crude oil should

be collected from the various processing plants and delivered

through a jointly owned pipeline system to California refinery

centers or to a west coast to mid-continent pipeline system as pro-

posed for Alaskan oil or Elk Hills oil if, after careful study,

such a strategy should prove both economically,feasible and envir-

onmentally less damaging than the alternative of tankering crude

oil. A definitive analysis of this strategy could be accomplished

as a part of the EIS being prepared for Lease Sale #48, or through

a grant from the Office of Coastal Zone Management through CEIP

(Coastal Energy Impact Program), or as a condition to future off-

shore development proposals by industry.

D 0 S C U A D R A S 0 F F S H 0 R E F I E L D

FINDING

PLATFORM C INSTALLED. Platforms A and B are already in pro-
duction, producing about 34,000 B/D oil and 11,000 MCF/D natural
gas. Union constructed Platform C in February 1969 and intended
to install it immediately. Following the 1969 blowout at Platform A,
however, Interior withdrew the permit for installation of Platform C.
In 1971 Interior denied Union's second application. Union filed
suit challenging the decision, and the litigation was settled in
Union's favor in August 1976. Union installed Platform C in March
1977.with production projected to beoin by fall 1977. Union expects
Platform C production to peak in 197@ at about 7,000 B/D oil and
2,400 MCF/D natural gas. Recoverable reserves in the Dos Cuadras
field are estimated at 88 MM barrelS oil and 27 BCF natural gas.

RECOMMENDATION

NO RECOMMENDATION. Since Platform C is'not subject to further

review, and because it requires no new onshore facilities, no recom-

mendation is made. .

C A R P I N T E R I A 0 F F S H 0 R E F I E L D

FINDINGS

SUN'S PLATFORM HENRY CONTINGENT ON LITIGATION AND EXPLORATORY
WELL. Existing production in the federal portion of the Carpinteria
field -- about 4,800.B/D oil and 2,600 MCF/D natural qas -- is from
two Phillips platforms on Lease 0166. The Carpinteria field extends
into Sun's lease 0240, and Sun has tried since 1970 to obtain per-
mission to install Platform Henry. Construction and emplacement of
Platform Henry is contingent upon resolution of pending litigation
and upon the results of further resource evaluation. It is esti-
mated by USGS that Henry could recover 13 MM barrels oil and nine
BCF natural gas. We estimate that a peak flow of 6,000 B/D oil and
4,000 MCF/D natural gas could occur in 1980 if.the litigation is
resolved by 1978 and Sun concludes that Platform Henry is still a
desirable proposal.

HENRY PRODUCTION TO MOBIL-RINCON. Sun's proposed Platform
Henry has been designed as a satellite production facility to
Platform Hillhouse on the nearby Dos Cuadras field. Equipment
on Henry would consist of the minimum necessary to produce and

test wells and transport the product. Sun Oil's development
plan proposes connecting Platform Henry by pipeline with Platform
Hillhouse where Sun maintains significant processing capability.
@From Hillhouse, Sun would transport oil and gas through existing
pipelines to the Mobil-Rincon processing plant for further process-
ing. Sun Oil owns part interest in Mobil-Rincon.

PHILLIPS-LA CONCHITA OPTION AVAILABLE. A development alter-
native would be to connect Platform Henry by pipeline to Phillips
Oil platforms Hogan and Houchin, located in the Carpinteria
field and linked by pipeline to the Phillips-La Conchita
processing plant. This alternattve would allow surplus capacity
at Mobil-Rincon to be reserved for other future production in
the Channel-. Peak production anticipated from Platform Henry is
well within the capacity of the Phillips-La Conchita processing
plant, but no surplus water treatment capability is available.

RECOMMENDATION

70. TRANSPORTING OIL AND GAS FROM PLATFORM HENRY. In review-

ing Sun's development plan for Platform Henry, USGS should evaluate

the option of redesiqning Platform Henry in order to send produc-

tion by pipeline to the existing Phillips platforms, and from there

to the Phillips-La Conchita facility for processing. If such re-

design renders the project economically infeasible, the original

development plan should be approved.

S A N T A Y N E Z U N I T

FINDINGS

SANTA YNEZ UNIT CONTROVERSY. Development of the Santa
Ynez Unit is the subject of considerable debate at both local
and state levels. The major issue is the means of transporting
processed crude oil to refineries: marine transport vs. onshore
pipelines. Exxon argues that it must use tankers or barges
because production levels and economic factors make a pipeline
infeasible. State and local agencies believe an onshore pipeline
would be economically viable, would reduce air pollution and oil
spill risks, and could be used by other Santa Barbara Channel
producers who would otherwise use tankers and barges. The Coastal
Commission issued a permit to Exxon containing provisions for
interim use of a marine terminal pending completion of a pipeline
feasibility study. Exxon believes this permit lacks sufficient
safeguards and assurances to enable it,to accept the terms involved
and, therefore, has pursued an offshore alternative beyond state
jurisdiction.

SANTA YNEZ DEVELOPMENT PLAN. The initial plan for this
unit is for development of one platform on a portion of the
Hondo field,with provisions for subsequent production systems
on the remainder of the field and future development of tl@io
additional fields within the unit area boundary. The develop-
ment plan includes the initial platform, pipelines to shore, a
new oil and gas processing plant in Las Flores Canyon, and a
new marine terminal in state waters directly offsho 're. If on-
shore facilities could not be obtained by Exxon, the plan in-
cludes an offshore alternative for processing and transshipment
of crude oil to refineries moored in federal waters. The Depart-
ment of the Interior approved the development plan in 1974 and
approved the offshore alternative contingent on a finding that,
after diligent and good faith efforts, Exxon was unable to
secure the necessary onshore permits under reasonable terms and
conditions.

INFLUENCE ON SANTA BARBARA CHANNEL DEVELOPMENT. The Santa
Ynez Unit contains half of the estimated potential reserves in
the federally leased Santa Barbara Channel. Exxon's development
decisions, therefore, will strongly-influence options for Channel-
wide oil and gas development. Specifically, crude oil produced
elsewhere in the Channel could be transported through a pipeline
developed.for Santa Ynez Unit production, reducing the costs of
.such a pipleine and also the need for tankers in theChannel as
a whole.

POTENTIAL OIL AND GAS RESERVES. Conservative estimates
show that the Santa Ynez Unit contains more oil and gas than all
other Santa Barbara Channel fields combined. High and low esti-
mates for the unit vary widely. USGS and Exxon concur on esti-
mated oil in place (three to five billion barrels). USGS has
estimated that 730 million to 1.1 billion barrels of oil with a
gas-oil ratio (GOR) of 500 cubic feet of gas per barrel could be
recovered from the unit. Exxon states that only 420 million
barrels of recoverable oil with a GOR of 1,500 have been identi-
fied as recoverable from the unit.

POTENTIAL PRODUCTION RATES. Assuming 420 million barrels
of recoverable oil, Exxon predicts peak oil production from the
unit at 80,000 B/D and has designed its onshore processin .g plant
for that limit (the offshore alternative is designed for 60,000
B/D).. The recovery of 730 to 1,100 MM barrels with a reasonable
rate of production implies peak flow rates of about 150,000 to
200,000 B/D. If the additional 300 to 700 MM barrels of oil
estimated by USGS is in fact recoverable, and Exxon fully develops
the unit, either the peak production rate will exceed the current
design parameters by as much as 120,000 B/D, or the producing
lifetime will be considerably longer than the 20 to 30 years
common to most offshore fields, or both.

USGS ROLE CRUCIAL. USGS is the only public agency with
access to information relied upon by Exxon to prepare its reserve
estimates. The Survey's 1973 estimate, however, has increased

uncertainty about recoverable reserves in the unit. California
agencies are dependent upon Exxon and the Geological Survey for
Santa Ynez Unit resource information and cannot,independently
reconcile the conflicting reserve and production estimates. The
key to early resolution of the controversy lies with the Geologi-
cal Survey.

PROGRESS IN THE SANTA YNEZ UNIT CONTROVERSY. Exxon's decision
to proceed with an offshore alternative is not irreversible, and a
mutually satisfactory agreement is still possible-, either by nego-
tiation or legal action. The California Attorney General has filed
an action to enjoin the Department of the Interior from permitt 'ing
Exxon to proceed with its offshore alternative. New developments
in the last year, including passage of the Coastal Act of 1976,
allow the State to consider alternative conditions for Exxon's on-
shore processing plant: such conditions have recently been forward-
ed to the Department of the Interior. The Santa Barbara County
Board of Supervisors adopted by unaminous vote a resolution urging
that Santa Barbara Channel crude oil be transported by onshore pipe-
line rather than by tankers, and that an industry/government task
force convene to evaluate specific pipeline options. Initial meet-
ings of the task force are now underway.

OPPORTUNITIES FOR ONSHORE PIPELINE TRANSPORTATION OF SANTA
YNEZ CRUDE OIL. Several options exist for transporting Santa Ynez
Unit crude oil north, south, or east by pipeline:

a. The original 140-mile pipeline route to Los Angeles
remains a viable alternative deserving additional study;

b. An alternative route to Los Angeles refineries via the
Santa Clara River Valley to Saugus and then south is
also deserving of study;

c. An alternative involving the conversion of Arco's exist-
ing Casitas gas transmission line between Ventura and
the Cuyama Valley to a crude oil transmission line could
allow for the moving of Santa Ynez Unit crude to the Elk
Hills-Bakersfield area, where existing pipelines link
northern, southern, and central California refineries; or,

d. The Point Conception LNG proposal, which would produce a
new pipeline corridor for two large natural gas pipelines
between that area and Bakersfield (and then to Los Angeles),
affords an additional option for pipeline routing into the
Elk Hills-Bakersfield area that has not yet been explored.

RECOMMENDATIONS

71. WITHDRAW EXXON'S OFFSHORE PERMIT. The Department of

the Interior should withdraw its approval of Exxon's offshore

alternative on the grounds that Exxon does in fact have the option

of a reasonable onshore development opportunity.

72. GEOLOGICAL SURVEY SHOULD ANALYZE SANTA YNEZ UNIT RESERVE

ESTIMATE. The USGS should obtain all geologic and geophysical

data and information held by Exxon pertaining to the Santa Ynez

Unit as provided for by USGS regulations (30 CFR 261). Using

this,information., the Survey should conduct a detailed analysis

of the resource potential of the unit and make its findings public

so that they may contribute to the evaluation of transportation

alternatives.

73. INTERIM USE OF TANKERS ACCEPTABLE. Any onshore pipeline

used to transport Santa Ynez Unit and other Santa Barbara Channel

production to refineries would take several years to construct.

To avoid delay in bringing Channel production to refineries,

state and local officials should permit the interim use-of tankers,

under operating procedures comparable to those negotiated for

Arco's South Elwood facility, while the onshore pipeline is evalu-

ated. If the pipeline is found to be economically feasible, interim

use of tankers should be permitted to continue until detailed

design and construction of the pipeline are complete. If the pipe-

line is infeasible, the interim permit should be made permanent.

S A N T A C L A R A U N I T

FINDINGS

RESERVE AND PRODUCTION ESTIMATES. If one platform is installed,
production could peak at l6jOOO B/D oil and 16,000 MCF/D natural gas
in,1982, with 44.6 MM barrels oil and 44.6 BCF natural gas ultimately
-recovered. With three platforms, production could peak at 38,000 B/D
oil and 45,600 MCF/D natural gas in 1983, with 113 MM barrels oil and
136 BCF natural gas ultimately recovered.

DEVELOPMENT OPTIONS. According to Chevron's Plan of Development
up to three platforms would be constructed and connected by pipelines
to one of four alternative processing sites:

a. Mobil-Rincon, using existing surplus capacity;

b. Chevron-Carpinteria, requiring some expansion-;

c. a new processing facility to be constructed in the
Ventura-Oxnard area; or,

d. an offshore processing facility.

Whichever alternative is used to process Santa Clara production,
Chevron has indicated a preference to transport the processed oil
to refineries via tankers, rather than by pipeline.

RECOMMENDATIONS

74. PROCESS AT EXISTING FACILITIES. Santa Clara production

should be delivered to the Mobil-Rincon processing facility

through a joint pipeline which also carries Mobil's Hueneme Off-

shore Field production. Mobil-Rincon is preferred over Chevron-

Carpinteria because it has substantially more surplus capacity,

is accessible to existing onshore crude oil pipelines, is more

remotely located from existing urban settlement, is not visible

from the highway or nearby beaches, and is not dependent on a

marine terminal for transshipment of crude oil to refineries as

is Chevron-Carpinteria.

75. IMPOSE AIR QUALITY SAFEGUARDS. Expansion permits for

either onshore facility should require that no additional reactive

hydrocarbons be emitted as a result of the increased throughput.

H U E N E M E 0 F F S H 0 R E F I E L D

.FINDINGS

MOBIL OPERATOR OF HUENEME FIELD. Mobil Oil operates two
adjoining leases three to nine miles due west of Port Hueneme
on behalf of itself and Union. Exploratory drilling has led
to discovery of the Hueneme Offshore field underlying both
leases.

PLAN OF DEVELOPMENT SUBMITTED AND PENDING. Mobil submitted
a proposed Plan of Development to USGS in May, 1976, and USGS
action is still pending. The Plan proposes installation of
one platform, from which an estimated 19 MM barrels of oil
could be recovered, with peak flow of 8,500 B/D in 1980. Mobil

expects to use all produced natural gas for energy requirements
on the platform. Mobil's proposed options for processing the
produced crude oil include the existing Mobil-Rincon facility,
a new processing facility in Ventura County in the area of
McGrath Lake, near Mandalay Beach, and, possibly, the Carpinteria
facility owned by Chevron.

OPTIONS FOR BRINGING HUENEME FIELD PRODUCTION ASH0R E' Mobil's
proposed options for pipelining Hueneme produced petroleum to shore
include, in order of preference:

a. a pipeline to the proposed Chevron Santa Clara Unit
platform, then a joint pipeline to a common onshore
processing facility;

b. a pipeline directly to the Mobil-Rincon facility, if
a joint pipeline with Chevron is not feasible;

c. a pipeline direct to the Dos Cuadras platforms and
connecting pipeline to shore; and,

d. a pipeline direct to a new onshore facility near
Mandalay Beach.

RECOMMENDATION

76. CONSOLIDATE DEVELOPMENT OF HUENEME FIELD WITH SANTA

CLARA UNIT.. Hueneme production should be transported to shore

via the Santa Clara.Unit pl'atform and processed at the Mobil-

Rincon plant.

P I T A S P 0 1 N T U N I T

FINDINGS

"PROMISING" DISCOVERIES. The Geological Survey credited
the Pitas Point Unit with a commercial discovery in 1969, but
Texaco has not decided whether to develop the find. Texaco
recently completed its third well on 0234, calling the results
"promising." If Texaco develops the Pitas Point discovery,
platforms could be proposed for OCS-P-0234 and connected with
a four-mile pipeline to Platform A on'the Dos Cuadras Field
or a ten-mile pipeline connection to the Mobil-Rincon process-
ing plant ashore. No reserve estimates are available.

RECOMMENDATIONS

77. PROCESS PITAS POINT OIL AT MOBIL-RINCON. If Texaco

develops a Pitas Point discovery, production should be processed

at Mobil-Rincon. Production from the Pitas Point Offshore field

should be accommodated in the existing surplus capacity of the

12-inch pipelines connecting the Dos Cuadras Field and Mobil-

Rincon. This alternative is preferred to constructing a new

pipeline directly to-shore.

78. SIZE PITAS POINT TRANSPORTATION FACILITIES TO HANDLE

OAK RIDGE. Pipelines compressors, and pumps intended for Pitas

Point production should be of a size to accommodate potential

production from the Oak Ridge Unit.

0 A K R I D G E U N I T

FINDINGS

NO DISCOVERIES YET. Five exploratory wells have been
drilled in the nine-lease Oak Ridge Unit, but none has been
certified by the Geological Survey as a discovery. Addition-
ally, two lease-line wells, dril.led cooperatively with Pauley
in an adjoining leased tract have not been certified.

NO RECOMMENDATION. Because no discovery has been made,

no recommendation is offered at this time.

S A N M I G U E L U N I T 0 1 7 4 , 0 1 7 5 , 0 1 7 6
0 1 7 7 , 0_1 7 8 , 0 1 7 9

FINDINGS

NO DISCOVERIES YET. These six leases were designated by
USGS as the San Miguel Unit on January 19, 1977. One explora-
tory well has been drilled on lease 0176. Exxon is the desig-
nated operator of the unit.

NO RECOMMENDATION. Because no discovery has been made,

no recommendation is offered at this time.

S A N T A C R U Z L E A S E S ( 0 2 0 0 9 0 2 0 1 0 2 0 6
0 2 1 1 , 0 2 1 2 , 0 2 1 3 9 2 2 1

FINDINGS

NO DISCOVERIES YET. Exxon, Arco, and Chevron own the seven
leases immediately north of Santa Cruz Island. In 1976, a proposal

to unitize the leases to form the Santa Cruz Unit was submitted
to USGS with Chevron proposed as the unit operator. This unit
proposal has since been withdrawn, following drilling of the
first exploratory well in the area. The primary term of these
leases currently expires July 2, 1978.

I POTENTIAL RESOURCES. The only well drilled in the area
found no producible resource. Based on very inconclusive data,
however, Chevron estimates that "potential resources" of ten
to 35 million barrels of oil and ten to 35 billion cubic feet
of gas could be discovered.

NO RECOMMENDATION. Because no discovery has been made,

no recommendation is offered at this time.

P A U L E Y L E A S E S ( 0 2 1 8 , 0 2 2 6

FINDINGS

NO DISCOVERIES YET. Eight.exploratory wells have been
drilled. Pauley and partners were making plans to drill the
ninth well, when it was prevented from doing so by the USGS
at the time of the Union Oil Company's oil spill. Pauley
and partners filed suit in the U.S. Court of Claims to recover
revenue-lost by being prevented from going ahead with drilling
and development on the -two leases plus the imposition of total
liability. The su-it is still in litigation.

NO RECOMMENDATION., Because no discovery has been made,

no recommendation is offered at this time.

A N A C A P A L E A S E S ( 0 1 9 8 , 0 1 9 9

FINDINGS

NO DISCOVERIES YET. Exxon is the sole owner of these
leases located three to five miles northeast of Anacapa Island.
The first exploratory well for either of.these leases. was begun
in January 1977. The primary term of the leases currently
expires July 2, 1978.

NO RECOMMENDATION. Because no discovery has been made,

no recommendation is offered at this.time.

SOUTH ELWOOD OFFSHORE F I E L D

FINDINGS

PRODUCTION TO INCREASE. South Elwood is the largest
field in the Santa Barbara Channel tidelands. Arco estimates
that more than 55 MM barrels of oil and 80 BCF natural gas
could be recovered from Platform Holly. Arco has obtained
all necessary drilling permits and the rezoning needed to
expand its Elwood facility to accommodate the expected produc-
tion increases. Santa Barbara County approval includes con-
ditions that strongly encourage conversion from tanker trans-
port of the processed crude to the use of an onshore pipeline
and would control the air quality impacts associated with
interim use of tankers. The rezoning conditions adopted by
the County are in substantial agreement with evolving state
policies for accommodating offshore oil and gas related
development. Arco still requires a permit from the California
Coastal Commission.

RECOMMENDATION

79. ARCO SHOULD BE APPROVED. The proposed Arco Elwood

facility should be approved by the Coastal Commission as con-

ditioned by Santa Barbara County. The Commission should obtain

commitments from Arco to evaluate and participate in an onshore

pipeline if it should prove feasible.

S U M M E R L A N.D A N D C A R P I N T E R I A ( S T A T E
0 F F S H 0 R E F I E L D S

FINDINGS

PRODUCTION MAY INCREASE. Chevron has obtained permission
to drill.up to 36 new production wells at its four platforms in
the Summerland and Carpinteria tidelands fields. These
wells could boost ultimate.recovery from the two fields by as
much as eight MM barrels oi-I and 16 BCF natural gas. New produc-
tion would be processed at the existing Chevron Carpinteria
facility and no expansion is required.

NO RECOMMENDATION. Because no additional permits are re-

quired for this development, no recommendati-on is offered at

this time.

E X X 0 N - L A S F L 0 R E S C A N Y 0 N
CONSOI-I -DATION OPPORTUNITY

FINDINGS

TIMING AND LOCATION ARE FAVORABLE FOR CONSOLIDATION.
Exxon, Arco, and Aminoil (previously Burmah) each propo'sed
to construct new petroleum-related facilities roughly'at the
same time and within six miles of each other. The new facili-
ties would duplicate each other's processes: two,oil and cas
processing plants and two marine terminals were proposed.
Consolidation of these operations could eliminate unnecessary
duplication and could provide for more efficient operations.
The opportunity for consolidation still exists.

THE EXXON PROPOSAL. Exxon proposed to construct a new oil
and gas processing facility at Las Flores Canyon and a new
marine terminal at El Capitan to handle anticipated production
from the Santa Ynez Unit. Ultimate design dapacities for the
Exxon proposal included 80,000 barrels of oil and 90,000 MCF
of gas per day treatment and separation capacity, initial
storage for 220,000 barrels of oil and double this amount for
ultimate storage, and up to 25,000 barrels per hour pumping
throughput for the marine terminal. Exxon expects production
from the Hondo field to peak at around 60,000 barrels of oil
and 90,000 MCF of gas per day by 1985. The Las Flores Canyon
facility is now an inactive proposal by Exxon, but legal pro-
ceedings initiated by the state may.reactivate it.

THE ARCO PROPOSAL. Arco has proposed to replace its
existing processing plant with a new and larger facility on
the same site in order to accommodate increased production from
Platform Holly in the South Elwood Offshore field, which is
owned"by Arco and Aminoil and operated by Arco. Design capa-
cities called for processing up to 20,000 barrels of oil and
5,000 MCF of gas per day and.storage for 100,000 barrels of
oil. Transshipment of the crude oil produced was assumed to
be handled through a long-term agreement with Aminoil. Arco
expects production to peak in 1979 or 1980.

THE AMINOIL PROPOSAL. Aminoil proposed a new marine
terminal at Naples to replace its existing marine terminal at
Elwood, This proposed facility could store 338,000 barrels
of oil-onsite and transfer 17,500-barrels of oil per hour to
tankers moored offshore. This proposal was intended specifi-
cally to handle the anticipated increase in production from
Platform Holly.

SAN MIGUEL LEASES COULD USE LAS FLORES CANYON. If the
San Mi-guel Unit contains commercial deposits of oil and gas,
and production can be managed so as not to disturb-pinniped
rookeries on the Channel Islands, processing capability on
the mainland coast may be required. The-Santa Ynez Unit devel-
opment plan, and particularly the Las Flores Canyon proposal,
is the only facility in the west end of the Channel likely to

8-76658 99

be capable of handling any production from San Miguel. East
Channel facilities are considered too far away to be practical
for processing requirements. Both Las Flores Canyon and the
San Miguel Unit would be operated by Exxon.

INITIAL COUNTY PROPOSAL FOR CONSOLIDATION. Timing and
location opportunities created by the separate Exxon, Arco,
and Aminoil projects have led to an integrated consolidation
proposal by the County of Santa Barbara. As initially con-
ceived, both Santa Ynez Unit and South Elwood Offshore field
production would be processed and stored at Las Flores Canyon
and transported to refineries by the sane system. Processing
and storage of the oil produced from both areas at the same
site could be accomplished within existinq design constraints
because their peak rates of production would not overlap.
Transportation options would include the new El Capitan marine
terminal or an onshore pipeline if it should prove feasible.
This consolidation at Las Flores Canyon would eliminate the
Arco-Elwood processing plant and the Aminoil marine terminal.

CURRENT COUNTY PROPOSAL FOR CONSOLIDATION. The current
county proposal for consolidation revises-the initial concept
by retaining the Arco-Elwood facility for processing only.
South Elwood Offshore production would be stored at Las Flores
Canyon and crude-oil transportation to refineries would be as
described above.

CRUDE OIL TRANSPORTATION IS TJJF CRITICAL OBSTACLE TO
ACHIEVING CONSOLIDATION. Exxon 'and Arco have indica@-e__dthat
consolidation of storage and transportation functions for both
producing areas is acceptable in principle. However, agreement
between the State and Exxon as to the method of determining a
transportation mode for crude oil has not been reached. Until
a method is agreed upon, consolidation at Las Flores Canyon
will not occur.

RECOMMENDATION (See also Recommendations 8, 9, 10, and 16 of
this Chapter.)

80. DELAY ACTION ON AMINOIL-NAPLES. Any permit applica-

tions regarding the Aminoil-Naples proposal should be held in

abeyance pendinq final resolution of the law suit involving

Exxon and the State of California, or until 1979, whichever

occurs first. Following a determination by the Santa Barbara

County Counsel that the suit has not or will not be adequately

resolved in 1979 or soon thereafter, the Aminoil-Naples proposal

may be considered.

100

M 0 B I L - R I N C 0 N P R 0 C E S S I N G P L A N T

FINDINGS

OWNERS, LEASEHOLDINGS, AND PROPERTIES. The Mobil-Rincon
facility is owned jointly by Gulf, Texaco, Union, and Mobil
(GTUM), and Sun, Superior Oil, and Marathon (the SSM Group).
These two lease-holding groups control 14 leases in the eastern
end of the Channel and four of the six discoveries currently
recognized by USGS. These two groups share ownership in the
12-inch oil and gas lines connecting the Dos Cuadras field with
Mobil-Rincon and the 22-inch oil transmission line connecting
Mobi'l-Rincon with Ventura. Between them, these two groups own
four of the seven federal OCS platforms in the Santa Barbara
Channel.

MOBIL-RINCON IS STRATEGICALLY LOCATED. Mobil-Rincon is
the largest processin@__plant near the eastern end of the
Santa Barbara Channel and is closer to all discovery areas
and designated units in the eastern Channel as a whole than
any other existing processing plant. The processing site
itself is not visible from the Ventura Freeway (101) or other
public viewing points because of its siting above the coastal shelf.

CAPABILITY TO HANDLE NEW PRODUCTION. Mobil-Rincon is
currently operating below its full capability. Present surplus
capacity can accommodate maximum projected rates of crude oil
and nautral gas production from Platforms C (Union), Henry (Sun),
Hueneme (Mobil), and the three Santa Clara Unit platforms
(Chevron) with some surplus capacity still remaining. Treatment
and disposal of waste water is a constraining factor and may
require equipment changes. Additional production from the Pitas
Point Unit discovery (Texaco) and any remaining undiscovered
fields in the, eastern Channel could be handled at Mobil-Rincon,
but.some expansion may be required. The processing plant site
can accommodate additi.onal equipment capable of doubling through-
put capacity for the plant without altering existing site grades
or making the equipment visible from important viewing points.

ADVERSE EFFECTS OF MOBIL-RINCON EXPANSION. Increased
throughput at Mobil-Rincon could cause significant localized
air pollution as a result of increased hydrocarbon emissions
from the plant. Areas affected by these emissions are not
easily identified because wind data for the area are extremely
limited. Considering only very generalwind information,-it
appears that Ojai Valley may receive some air pollution as a
result of any activity at'Mobil-Rincon.

RECOMMENDATIONS

81. PROCESS NEW EAST CHANNEL PRODUCTION AT MOBIL-RINCON.

The State Lands Commission, the California Coastal Commission,

and the Ventura County Planning Commission should adopt a policy

101

encouraging the use of the existing Mobil-Rincon for new

production from eastern Channel OCS development.

82. ENCOURAGE WATER SEPARATION AT PLATFORMS. Expansion

of Mobil-Rincon would be required in order to handle increased

production during 1982-1986. To minimize expansion requirements,

produced water should be separated at the platforms if feasible.

83. METEOROLOGICAL DATA IS NEEDED. The users of Mobil-

Rincon should immediately establish a meteorological data gather-

ing system to determine the existing and potential air quality

.impacts of the Mobil-Rincon facility. Such data collection must

be available in evaluating any expansion proposal for the site

operations.

L E A S E S A L E # 3 5

FINDINGS

FOUR DISTINCT PLANNING AREAS. Each of the four sub-areas
of Lease Sale #35 are more or less independent of each other,
and each may require separate development strategies. The
four areas are Santa Rosa-Cortes Ridge North, Santa Rosa-Cortes
Ridge South (Tanner Banks), Santa Barbara Island, and San Pedro
Bay. The first three areas (the Outer Banks) are remotely
located from existing oil and gas developments while San Pedro
Bay is essentially contiguous with the Long Beach-to-Huntington
Beach oil and gas region.

LEASE SALE #35 PLANNING PROBLEMS. The remoteness and the
fragile environFWn--tal conditions of the Outer Banks are major
concern for any future oil and gas development in these areas.
Development in San Pedro Bay could pose serious problems as
the fixed offshore structures would be built in the existing
vessel traffic separation scheme.

OUTER BANKS TRANSPORTATION OPTIONS. There are two options
for transporting crude oil produced from the Outer Banks, either
surface transport or pipelining. If surface transport is used,
all Outer Banks production would be delivered directly to the petro-
leum terminals of California's major ports. With the pipeline
option, there is but one feasible route from the Santa Rosa-Cortes
South area to the mainland -- north alonq the Santa Rosa-Cortes
Ridge until the Channel Islands are reac@ed. Production from

102

the Santa Rosa-Cortes North fields can be included in south
area production or move independently of it in a pipeline from
the Channel Islands to a landfall in the Ventura area. Again,
there is but one feasible pipeline route from the Santa Barbara
Island area to the mainland -- north to the Channel Islands by
foll,owing the submarine ridge connecting Santa Barbara Island with
Anacapa Island. This line could tie into the pipeline carrying
production from the Santa Rosa-Cortes areas to Ventura.

SAN PEDRO BAY TRANSPORTATION OPTIONS. Surface transport
is not lik ly to be competitive with pipelining new production
in San Pedro Bay since the platforms will be cl-ose to land.
With pipelining, there are two transport ways to San
Pedro Bay production to shore: a common pipeline gathering
system that would take all production to a single landfall
area, or separate pipelines running from each'discovery. There
are two basic routes for a common pipeline: one to Huntington
Beach, because it is the closest landfall to a majority of the
leases; the other to Lonq Beach, because it has the best access
to refineries in the Los Angeles Basin.

RECOMMENDATIONS

84. LEASE-AREA PLANS. Each of the four sub-areas of Lease
Sale #35 should be developed according to lease-area plans prepared

jointly by industry and government. (See Chapter 19 for a descrip-

tion of lease-area plans.) These plans would coordinate all phases

of development on an area-by-area basis to allow for optimum resource

recovery. The lease-area plans would consider the timing, rates of

production, and transportation modes for each area as a whole, after

exploration of each area is sufficiently complete to determine the

probable recoverable resources. No development or production should

commence prior to completion of a lease-area plan with the exception

provided for in recommendation #57 of Chapter 9.

85. OUTER BANKS TRANSPORTATION STRATEGY. If commercially recov-

erable resources are discovered in the Outer Banks and analysi's
indicates that pipelines to shore are economically and technically

feasible, a single pipeline network serving the various producing areas

should be utilized. Future lease sale offerings in the Outer Banks

should be designed to maximize the economic incentives for pipeline

103

construction, and development plan approvals should be conditioned

to encourage participation in a single pipeline system. An off-

shore crude oil pipeline company, similar to the natural gas

Pacific Offshore Pipeline Company (POPCO), could be formed to

develop and maintain the necessary system. (See Chapter 10

for additional findings.)

86. SAN PEDRO BAY TRANSPORTATION STRATEGY. Transportation

,of crude oil and natural gas produced in San Pedro Bay should

be through one integrated pipeline network. Huntington Beach,

or Long Beach, may be the preferred landfall; each should be

evaluated on economic, environmental, and social considerations.

(See Chapters 20 and 21 for further background.)

S A N P E D R 0 B A Y ( S E E A L S 0 N A V I G A T 1 0 N A L
S A F E T Y I N C H A P T E R 1 0

FINDINGS

1. OWNERSHIP. Six different petroleum company consortiums
own San Pedro Bay leases. Groups led by Chevron and Shell Oil
Company are clearly the dominant lease holders. Other consortiums
are headed by Gulf, Texaco, Mobil, and Challenger. All lease
holders, with the exception of Challenger, have world-wide and
southern California OCS production experience-,'.and all own onshore
property in the vicinity of San Pedro Bay.

OIL AND GAS POTENTIAL. San Pedro Bay is generally regarded
as. containing the best oil and gas prospects offered in Lease
Sale #35. USGS estimates that 355 to 946 MMB of oil and 301
to 821 BCF of natural gas could be recovered from the several
prospects underlying the San Pedro Bay leases. Exploration
to date by Shell and Chevron discovered the existence of oil
and gas accumulations in a portion of one prospect; Shell has
indicated that recoverable oil and gas identified to date
may be less than 200 MMB of oil and 34 BCF of natural gas.

POSSIBLE PRODUCTION. Production from this early discovery is de-
pendent on many factors; Shell has indicated it could begin by 1979.
Under typical operating conditions, a new offshore field of 200 MMB of
oil and 34 BCF of natural gas would result in a peak production rate
of 30,000 to 40,000 B/D oil and 7,000 to 8,000 MCF/D natural aas. If
recoverable reserves equal to the USGS high range estimates
are discovered in San Pedro Bay, peak production rates in ex-
cess of 200,000 B/D oil and 180,000 MCF/D gas could occur.

104

AVAILABLE TREATMENT AND SEPARATION FACILITIES (PROCESSING
PLANTS). There is no existing or planned processing plant or
combination of plants available for handling production at the
rates mentioned above. At least one new processing plant site
will be required in the vicinity of San Pedro Bay to accommodate
this new production. Possible onshore sites with oil-related
zoning exist in Los Angeles and Long Beach Harbors and the City
of Huntington Beach. Offshore processing is a possible alter-
native to onshore processing.

TRANSPORTATION OF OIL AND GAS TO PROCESSING SITES. Federal
leases in San Pedro Bay range from three to ten miles offshore.
Based on typical OCS development in southern California and the
Gulf, this proximity to the mainland makes -pipelining crude oil
and natural gas to shore economically and environmentally pref-
erable to offshore processing solutions or barging produced
crude oil to a processing site. There are no pipelines between
the federal leases in San Pedro Bay and onshore areas. The
closest mainTand area already developed for oil and gas extrac-
tion is Huntington Beach. Other possible landfalls would be
in Los Angeles/Long Beach Harbors; pipeline routes to these
destinations, however, would have to avoid areas used heavily
for dredging or fill.

AVAILABLE PIPLEINES TO TANK FARMS AND REFINERIES. Los
Angeles and Long Beach Harbors are served by numerous pipelines
connecting Long Beach production sites and major tanker loading
operations with the many refineries in the Los Angeles Basin.
Major pipeline operators in the Harbors are Mobil, Union,
Texaco, and Arco. Pipelines from the Harbors or Huntington
Beach have a direct tie-in with the Four Corners Pipeline.

RECOMMENDATION

87. PROCESSING SITE SELECTION. The major lease holders

in San Pedro Bay -- Shell, Chevron, and Gulf -- should consider

the possibilities of consolidating the treatment and separation

of produced oil and gas at an expanded@. existing processing plant

or at a new facility onshore. The Interior Department and state

agencies should notify all OCS operators in San Pedro Bay that a

floating, offshore processing station is an unacceptable alternative

for this area because of the significant risk of rammings and the

additional environmental risk represented by the oil contained in the

offshore processing equipment. (See also Recommendation 2 of Chapter 10.)

105

CHAPTER 12:

OCS LEASE SALE #48

FINDINGS

NEW LEASING OPPOSED UNDER CURRENT CONDITIONS. The State
.of California a ocal governments oppose Lease Sale #48 on
several grounds: 1) critical environmental and oil and gas
resource information has not been provided for analysis; .
2) leases do not permit the Secretary of Interior to cancel a
lease if new information reveals extraordinary environmental
hazards; 3) state and local governments are given an inadequate
role in the federal OCS management process; 4) leases are pro-
posed for sale.near sensitive environmental and recreational
resources; and, 5) the enactment of amendments to the OCS Lands
Act embodying many needed reforms is expected soon. The S.tate
of California does not oppose OCS oil and gas leasing and
development per se, but does object to leasing and development
without the above safeguards.

TRACTS SELECTED. The Department of Interior has selected
217 tracts for Lease Sale #48 EIS including all the unleased
areas of the Santa Barbara Channel outside the ecological
preserve. Preliminary tract selection implies a commitment
to lease: no OCS sale for which an EIS was prepared has ever
been cancelled.

NEGATIVE NOMINATIONS. State and local governments identi-
fied specific tracts for exclusion from Lease Sale #48 based
on concerns for air quality, oil spill risks, navigational
hazards to shipping, and disturbance of ecologically productive
areas, including sensitive bird ' seal, and sea lion breeding
grounds. Interior Department tract selections reflect an over-
riding concern for oil and gas potential, however, and virtually
ignore the negative nominations made by state and local
governments.

*For additional discussion see Chapter 22.

107,

FEDERAL AGENCIES SHARE CALIFORNIA'S ENVIRONMENTAL CONCERNS.
The Environmental Protection Agency recommended deletion of the
Santa Barbara Channel from Lease Sale #48 because of the hazard-
,ous potential for adverse effects. The U.S. Marine Mammal
Commission recommended the establishment of a six-mile buffer
zone around certain islands in the Channel and a delay of
further Channel leasing pending the completion of environmental
baseline studies. The U.S. Fish and Wildlife Service reaffirmed
its proposal for buffer zones, as posited in Lease Sale #35.

CALIFORNIA ENERGY NEEDS. Oil from Lease Sale #48 will
not be needed in California before 1990 at the earliest. The
Federal Energy Administration projects an early West Coast
crude oil surplus of 400,000 to 800,000 barrels per day, due
in large part to Alaskan production. Current projections indi-
cate the critical natural gas shortage in southern California
beginning in 1980. OCS gas may help alleviate projected
shortages, but it will not eliminate the need to augment the
gas supply by extraordinary measures such as the importation of
LNG.

TWO MAJOR CONCERNS ELIMINATED.' The Department of the
Interior's new (May 17, 1977) Na nal OC-S Leasing schedule
and policy appear to eliminate two major state and local govern-
ment concerns over Lease Sale #48 until at least early 1979
and emphasize "providing adequate time ... for resolving con-
flicts and involving coastal states in a significant manner"
in the OCS leasing and development process. The new schedule
practically assures the Amendments to the Outer Continental
Shelf Lands Act will be enacted in time to effect the Lease
Sale #48 process.

PREPARATION OF THE EIS CONTINUES. Even though Lease Sale
#48 has been postponed, the BLM is continuing the preparation
of an EIS. The timeframe for completing the EIS has been
expanded, but the EIS will still consider tracts opposed for
leasing by California state and local governments.

RECOMMENDATIONS

88. LEASE SALE #48 SCHEDULE. Lease Sale #48 should not

be rescheduled until Congress enacts equitable oil spill lia-

bility legislation and amendments to the OCS Lands Act

providing for the release of environmental and oil and gas

resource information to state and local governments, a stronger

state and local voice in leasing and development decisions,

and an opportunity for the Secretary of Interior to decide

after exploration, whether lease tracts will be developed.

108

89. LEASE SALE #48 EIS. State and local governments should

accept the Interior Department's invitation to participate in

preparation of the EIS. The State should establish an EIS task

force to review the Interior Department's drafts and monitor

the preparation, commenting, and public hearing @rocesses of

the EIS. The Interior Department should distribute all work

programs and preliminary drafts to state and local governments

in a timely fashion.

90. OPR. The Governor's Office of Planning and Research

should coordinate state and local government involvement in

the Lease Sale #48 EIS process and the formulation of lease

stipulations until the Coastal Commission is given responsi-

bility for coordinating California's involvement in OCS

activiti,es (see Recommendation 13 of Chapter 4).

91. EIS HEARINGS, The Interior Department should hold

public hearings on the DEIS and EIS in each of the affected

coastal counties, allowing at least 45 days to review the

documents prior to the scheduling of hearings.

92. PREFERENCE FOR ADDITIONAL LEASES. When additional

tracts are leased off southern California, the first priority

should be filling in areas leased in Lease Sale 435 on thp

Tanner Banks and the Santa Rosa-Cortes Ridge in order to

improve the economics of an offshore oil pipeline from those

areas and to increase the chance that gas discoveries are

sufficiently large to justify development. Fill-in tracts in

the San Pedro Bay should also be fully considered for priority

leasing but only if devel opment can proceed without siting

permane nt structures in the vessel traffic lanes

109

(see Recommendation 2 of Chapter 10). California state and

local government should further identify and document in the

greatest possible detail tracts that are acceptable for

future leasing.

Photo opposite: Clean Seas, Inc., deploying Vikoma
Seapack boom for containment of a hypothetical oil spill.
Platform Houchin (Phillips) in background.

110

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CHAPTER 13

OCS MANAGEMENT:
THE PLAYERS AND THE RULES

Offshore oil and gas development on the outer continental shelf (OCS) is
managed through a complex system involving.government at all three levels --
federal, state, and local -- each with its own responsibilities and powers. This
chapter examines the federal leasing and management system, the regulation of
OCS-related onshore development, and the relaiionship of the federal Coastal'Zone
Management Act to offshore oil and gas development. Legislation pending in the
U.S. Congress on the printing date of this report will put into law some proce-
dures described in this chapter that have been carried out as a matter of regula-
tion or practice. It will also strengthen the rol.e of the states in the OCS
leasing and management process and provide more stringent environmental safeguards.

UNDERSTANDING THE FEDERAL LEASING
AND MANAGEMENT PROCESS

The Outer Continental Shelf Lands Act mandates procedures for the leasing
and development of offshore oil and gas lands. l/ The Act authorizes the Secretary
of the Interior to offer oil and gas lease tracts no larger tharf 5,760 acres (nine
square miles) for competitive bidding. Leases are for a five-year term, or for
as long as oil and gas are produced in paying quantitie.sor the lessee conducts
drilling or well reworking activities to restore or increase production from a
well.

The Secretary of the Interior delegates the responsibility for.leasing and
managing offshore lands to two bureaus within the Interior Department: the Bureau
of Land Management (BLM) and the U.S. Geological Survey (USGS). BLM acts as a
leasing agent and property manager. USGS performs technical studies of the geology
and mineral resources of federal lands and regulates the safety of oil and,gas
drilling operations.

L E A S I N G 0 F F E D E R A L 0 C S L A N D S

PRE-LEASE SALE EXPLORATION

Before the Department conducts a lease sale, it grants permits to explore broad
offshore areas by passive methods -- including measurements of changes in the

113

earth's magnetic field and local variations in the earth's gravity, and identifi-
cation of natural oil seeps -- to identify promising geologic formations. 2/
The industry then collects geophysical and geologic data to gain more detaTled
knowledge of promising areas.

Geophysical data collection techniques include seismic, gravity, and magnetic
surveys. By measuring the velocity of shock or seismic waves sent through various
rock formations beneath the sea, it is possible to evaluate petroleum potential
and identify hazardous conditions such as surface faulting, slide areas, or shallow
gas pockets. Identifying hazardous areas-is necessary to assure that an area is
safe for drilling and installation of platforms. Slight changes in the force of
gravity or small warps in the earth's magnetic field indicate changes in the rock
structure and rock densities below the ocean floor. 3/

Geologic exploration of the OCS involves bottom sampling, shallow-core drill-
ing, and, in some cases, deep stratigraphic test drilling.. Data from these activi.-
ties are used to determine the general geology of an area. Bottom samples are
collected by dropping a weighted tube to the ocean floor and retrieving it with an
attached wire line. Shallow-core drilling uses conventional rotary drilling equip-
ment, and is usually limited to the recovery of several feet of consolidated rock.
In areas where there has been little or no drilling to discover oil and gas, a
deep stratigraphic well may be drilled to gather information on the relative posi-
tion of the strata or rock layers of the earth's crust. Federal regulations
prohibit these wells from being drilled beyond a limited depth on geologic struc-'
tures in order to prevent the actual discovery of oil and gas in advance on a lease
sale and to reduce the possibility of a blowout. 4/ Often a number of oil compa-
nies will joi.n with USGS to drill a stratigraphic test well under a shared cost
agreement.

Private businesses contract with oil companies or the federal government to con-
duct exploratory activities. A single company or the federal government may arrange
independently to obtain exploratory data, or join in a number of combinations to
share the costs of such work. Exploration companies sometimes collect data on a
speculative basis and offer it for sale on the open market.

Anyone engaging in pre-lea'se sale exploration must obtain an "exploratory
permit" from the Area Supervisor of the USGS. In California and other coastal
states which have cooperative agreements with the Department of the Interior, the
applicant must stipulate that he*will abide by the regulations of the adjoining
coastal state and obtain the permission of the U.S. Corps of Engineers to ensure
that exploration activities will not create a hazard. He must also comply with
health and safety regulations of the Coast Guard and Occupational Health and
Safety Administration. Under new regulations effective June 23, 1976, geologic
and geophysical data collected on the OCS under an exploratory permit must be
made available to the USGS. 5/

FIVE-YEAR LEASING SCHEDULE

A five-year national leasing schedule guides generally BLM's OCS leasing
activities. The schedule identifies broad geographic areas such as "Southern
California" and "Mid-Atlantic" and lease sale dates for each area-. BLM is not
required to adhere strictly to the schedule; and in practice, most lease sales
are delayed several months beyond the originally scheduled date. USGS assists
the BLM in preparing the five-year leasing schedule by recommending areas with
promising oil and gas potential. BLM issues a draft schedule through the

114

Federal Reqister for comment by other federal agencies, states, local governments,
the oil industry and other interested parties. Based on comments concerning oil
and gas potential, environmental impacts, proximity to market, market value, energy
demand and supply, and availability of technology, BLM publishes a final national
leasing schedule indicating dates for sales and major events in the.process leading
up to an actual sale for each area. 6/

One of the-principal motives for developing fede 'ral OCS resources has been
demands for the governmental revenues which lease sales produce. OCS revenues are
substantial, averaging about $3.5 billion annually and totaling over $6.7 billion
in fiscal year 1974. 7/ In recent years, however, the need to increase OCS oil
and gas production-has overridden the importance of increasing OCS revenues.

On April 18, 1973, President Nixon-ordered the OCS leasing rate increased
from one million acres-per year to three million acres per year. Nixon announced
on January 23, 1974, only nine months later, that the leasing rate would be further
accelerated to ten million acres per year beginning in 1975. There were several
reasons for these enormous increases. In part, they responded to the energy crisis
and the Arab oil embargo. Additionally, the acceleration of the leasing rate in
January, 1974, against the recommendations of BLM and USGS, strengthened the role
of the Interior Department in energy issues against the encroachments of the new
Federal Energy Office, subsequently the Federal Energy Administration. 8/ Had
the ten-million-acre goal been achieved in 1975, the amount of acreage leased in
that one year would have almost equalled the total acreage leased in the previous
21 years of the program. In fact, only about 1.7 million acres of the OCS were
leased in 1975.

When President Ford took office in August, 1974, he initially affirmed the
ten-million acre per year leasing goal. However, widespread opposition from states,
environmentalists and the U..S. Congress caused him to reduce this goal to six sales
per year with all, areas where little or no leasing had occurred previously (frontier
areas) opened by 1978. After encountering numerous delays in implementing this
schedule, Secretary of Interior Kleppe issued a revised national leasing schedule
on January 12, 1977. The schedule called for leasing in all frontier areas by 1980.

ENVIRONMENTAL BASELINE'STUDIES

In frontier areas, BLM conducts biologic and oceanographic studies to deter-
mine an environmental baseline against which the effects of future oil and gas
development a.ctivities.!can be measured. Generally, separate contractors perform
four tasks: (1) conduct a survey of published reports on the environment and
marine resources of the area; (2) make a survey to establish the baseline for
future comparisons; (3) perform research necessary to close gaps in the data; and
(4) establish a monitoring program to detect environmental changes caused by
exploration and development.

RESOURCE REPORTS

BLM's first step in carrying out the lease sale process for a particular area
is to request resource reports from various federal agencies and the governors of
adjacent states. The Geological Division of USGS provides information on the
general geology and environmental hazards of the region. This summary report and
the supporting data.are available to the publi.c., but the information is not site-
specific.

9--76658 115

Other federal agencies and adjacent states report to BLM on the possible
effects of leasing on the environment and potential conflicts with other offshore
and coastal activities including shipping, fishing, recreation, or national
defense.

Resource report requests are the first official indication of specific tracts
being considered for inclusion in a lease sale area. Resource reports filed by
the Environmental Protection Agency, Fish and Wildlife Service, National Park Ser-
vice, U.S. Coast Guard, National Oceanic and Atmospheric Administration, and the
Defense Department contain information which is valuable to state and local govern-
ment for evaluating their own concerns over a proposed lease sale. BLM does not
automatically publish the resource reports. However, the Pacific*Coast OCS office
did make Lease Sale #48 reports available to California state and local governments
upon request.

CALL FOR NOMINATIONS

After evaluating resource reports, BLM issues a call for nominations of
individual tracts in the lease sale area. Notice of the call appears in the
Federal Register and a press release. Oil companies indicate positively nominated
tracts in which they have an interest. In addition, any interested public agencies
or persons, such as state and local governments and environmental groups, may
positively or negatively nominate tracts, or recommend special conditions for
leasing. The environmental, technical, or economic reason for excluding or offer-
ing a tract only under special conditions should accompany such nominations in
order to have them fully considered by BLM.

All nominations are submitted to the BLM Director, with copies to the BLM
field office.and the USGS Area Oil and Gas Supervisor for the area of the pro-
posed sale. Usually, nominations are due 60 days after the call. The Interior
Department now plans to hold lease sales 19 months after issuing the call for
nominations.

TRACT SELECTION

For California lease sales, the Pacific Coast OCS office of BLM reviews
resource reports and nominations with the area USGS office to select tracts for
further evaluation in the lease sale environmental impact statement. Oil and gas
potential, avoidance of geologic hazards, extreme environmental impacts, and
danger of drainage by production on adjacent leased tracts, are criteria that
influence tract selection. These tract selections are presented to Department
officials in Washington, D.C. BLM announces the approved tract selections usually
60 to 90 days after nominations close.

ENVIRONMENTAL IMPACT STATEMENT

The National Environmental Protection Act (NEPA) requires the preparation
of an environmental impact statement (EIS) prior to any major federal action. 9/
After selecting tracts, BLM, with assistance from other federal agencies, begins
to prepare a draft environmental impact statement (DEIS) on the proposed lease
cale. In 1976. the Pacific OCS office of BLM initiated a new policy of inviting
state and local qovernment participation in the preparation of the DEIS for Lease
Sale #48. A DEIS may take as long as one year to prepare. The President's Council
on Environmental Quality (CEQ) reviews the completed DEIS, and BLM publishes notice
of its availability for public review in the Federal Register and in a news release.

116

No regulation requires the BLM to hold a public hearing on the DEIS. However,
as a matter of practice, BLM schedules at least one public hearing, and often more,
in locations adjacent to the lease sale area. Hearings occur about 30 days after
the DEIS becomes publicly available, and there is a period of 45 days after the
hearing for interested parties to submit additional. comments.

After the comments have been reviewed, BLM prepares the final environmental
impact statement (FEIS). Completion of the FEIS may require from two to four months.
The FEIS serves as the basis for the Secretary's decision to hold a sale, exclude
specific tracts from the offering and/or to offer particular tracts for sale only
under special conditions. The public review procedure for the FEIS is the same as
that for the DEIS.

DECISION BY THE SECRETARY OF THE INTERIOR

After publication of the FEIS, BLM prepares a Program Decision Option Document,
(PDOD) for the Secretary, containing economic and environmental information relating
to the proposed lease sale. It lists all recommended special lease conditions and
all tracts proposed for leasing. No earlier than 30 days after submission of the
FEIS to the CEQ, the Secretary decides whether to hold the proposed sale and which
tracts to offer for sale and what the lease terms will be.

LEASE SALE

At least 30 days before he holds a lease sale, the Secretary publishes a
notice of the sale in the*Federal Register and issues a press release. The notice
specifies tracts to be offered for sale; lease conditions -- including any special
stipulations for particular tracts -- bidding procedures; and the date, place, and
time for receiving and opening bids.

Only U.S. citizens and nationals; aliens admitted for permanent residence; U.S.
corporations; or associations of such citizens, nationals, resident aliens, or cor-
porations may bid. Bidders who have an average daily production in excess of 1.6
MMB of crude oil, natural gas, or liquefied petroleum products cannot submit joint
bids together. 10/ Under this provision, the following companies cannot bid jointly:
Texaco, Exxon, Tm-oco, British Petroleum-Alaska, Chevron, Gulf, Mobil, Shell, and
Standard of California.

Each bid is sealed and accompanied by a check, money order, or bank draft in
the amount of 20% of an amount specified by the Secretary as the bonus bid. All
bids are read publicly; the Interior Department then has 30 days to make the deci-
sion, on the basis of tract evaluations, to either accept or reject the highest
bid on each.tract. USGS calculates tract evaluations based on resource estimates
derived from geologic and geophysical data. These tract-specific resource estimates
and tract evaluations are not avail'able to state and local governments or to the
public. The highest bidder must pay, upon notice of'acceptance, the balance of
the bonus and the first year's rental. ll/ He must also furnish a corporate surety
bond in the sum of $50,000 conditioned Tn compliance with all lease terms, unless
he already maintains or furnishes a bond in the sum of $300,000 conditioned on com-
pliance with the terms of leases held by him in the Gulf of Mexico, along the
Pacific Coast, or along the Atlantic Coast. 12/ Leases become effective on the
first day of the month following the signing, or earlier, if specified.

117

M A N A G E M E N T 0 F F E D E R A L L A N D S U N D E R L E A S E

After the issuance of a lease, the USGS enforces requlations and OCS Orders
and lease stipulations, collects rents and royalties, and supervises lease opera-
tions. The Area Oil and Gas Supervisor for each reqion performs these functions.
The Director of USGS designates lease supervisors from the Conservation Division.
The Supervisor responsible for California is the Pacific Area Oil and Gas Super-
visor in Los Angeles.

RENTS AND ROYALTIES

For each year prior to the discovery of oil and gas on a tract, a rental rate
of $3.00 per acre in unproven areas and $10.00 per acre in proven areas is paid to
USGS. The Secretary of Interior fixes a royalty rate at no lower than 12 1/2% of
production. 13/ The royalty rate is 16 2/3% on most tracts, but a rate of 33 1/3%
was set for six highly promising tracts in San Pedro Bay offered in Lease Sale #35.

REGULATIONS, OCS ORDERS, AND LEASE STIPULATIONS

A complex array of regulations, orders, and lease stipulations governs oil
and gas exploration, development, and production on the OCS. USGS enforces requ-
lations'. orders, and stipulations pertaining to exploration, development, and
production activities and disposal of royalty oil; and BLM qrants pipeline rights-
of-way. The Secretary promulgates regulations pursuant to the Outer Continental
Shelf Lands Act 14/ as necessary "for prevention of waste.and [for] conservation
of the natural resources of the Outer Continental Shelf 15/ Such resources
include "marine life, recreational potential, and aesthetic vaT-ues, as well as
the reserves of gas and oil." 16/ Other agencies, includino the Coast Guard and
U.S. Army Corps of Engineers, also issue and enforce reaulations relating to some
aspects of offshore oil and gas develonment as explainea below.

OCS Orders are formal and numbered orders that govern most of the daily drill-
ing and production operations on leases in a region or :major portion of a region.
The USGS Area Oil and Gas Supervisors issue OCS Orders, with the prior approval of
the Chief of the Conservation Division, USGS. 17/ Twelve OCS Orders are now in
effect in the Pacific area. One may obtain copies of these Orders from the USGS
Pacific Area Oil and Gas Supervisor in Los Angeles. The Supervisor may also issue
Orders to govern lease operations on a specific lease or leases. 18/

Lease stipulations may vary from lease tract to lease tract. They are usually
detailed lease terms and tailored to geologic and biological conditions found in
specific areas or lease tracts. For example, Stipulation 6 for Lease Sale #35
placed special conditions on drilling and production conducted in or near unique
biological areas of the Tanner Bank and Cortes Bank. In other instances, lease
stipulations may be used to provide detailed procedures 'for requirements stated
more broadly in regulations or OCS Orders. When the Secretarv of the Interior
decides to hold a lease sale, he also decides what lease stipulations will apply
to specific lease tracts. Lease stipulations appear in the federal Register along
with notice of the lease sale.

State and local governments and other interested persons may recommend new
or modified regulations, OCS Orders, and lease stipulations to the Interior

118

Department. Regulations and OCS Orders ar6 formulated through a formal process
conducted in accordance with the Administrative Procedures Act.1 9/ Drafts of
the regulation or order appear in the Federal Register for review and comment.
The agency proposing the regulation or order re7i@ses it after reviewing the com-
ments and publishes the finalized version in the Federal Register.

The Secretary develops lease stipulations in a different manner from regu-
lations and-orders. The DEIS recommends appropriate lease stipulations. These
are then subject to industry, government, and public review through the EIS review
and public hearing process. In addition, any party may recommend lease stipula-
tions to the Secretary during the period when he is Considering the decision to
hold a lease sale.

POST-SALE EXPLORATION

The present federal leasing and management system prohibits the drilling of
any wells to discover oil and gas until after a lease sale. The drilling of
exploratory wells distinguishes pre-sale exploration and post-sale exploration.

If the record owner does not conduct operations on a lease, he must desig-
nate an operator for the lease to the Oil and Gas Supervisor. 20/ If a single
company owns a lease, that company will usually be the operator. If a consortium
of companies owns a lease, which is a common arrangement, the consortium selects
one of the joint owners as operator.

Before exploratory drilling can begin, the operator must obtain approval of
an,exploratory drilling plan and various permits from USGS. The exploratory
drilling plan must include: (1) a description of drilling*vessels, platforms,
or other structures, showing their location, design, and major features, including
features pertaining to pollution prevention and control; (2) the general location
of each well, includin surface and projected bottom-hole location for direction-
ally drilled wells; (3? structural interpretations based on available geologic and
geophysical data; and, (4) such other pertinent data as the Supervisor may
prescribe. 21/

USGS prepares an environmental assessment of the exploratory drilling plan
within 30 days of the date the plan was filed and decides whether an EIS is re-
quired. All major federal actions significantly affecting the quality of the
human require preparation of an EIS. 22/

CEQ guidelines to identify such actions state that agencies evaluate the need
for an EIS with a view to the overall cumulative outcome of proposed and related
federal actions and projects. Although the proposed action may affect only a
small area, the statement must be prepared if there is the potential that oil and
gas development may change the environment. CEQ guidelines specifically state
that highly controversial Proposed actions "should be covered in all cases." 23/
EISs for exploratory drilling on the OCS are generally not the rule; however, there
was an exception requiring an EIS for the resumption of exploratory drilling in the
Santa Barbara Channel when the moratorium on drilling'imposed after the 1969 blow-
out was lifted. In the event the USGS Area Supervisor determines an EIS is neces-
sary, state and local governments and other interested persons or groups have an
opportunity to comment on the proposed drilling through the DEIS and HIS review
processes.

119

After the USGS approves an exploratory drilling plan, the operator must
obtain a permit to drill. The application, filed with USGS, must include infor-
mation regarding the proposed wells, meet requirements for controlling wells, be
consistent with the exploratory plan, and describe the blowout-prevention
program. Z4/ The BLM and Fish and Wildlife Service review and comment on the
explorato-ry- drilling plan and drilling permit application. The U.S. Army Corps
of Engineers must also issue a permit before drilling can begin.

It is the responsibility of the Corps of Engineers to prevent obstructions
to navigation in the navigable waters of the U.S., including the OCS. 25/ The
Corps must approve the location of all offshore structures, including movable
drilling ri-gs engaged in exploratory drilling. The installation of adequate
markings, beacons, or other devices specified by the Corps is necessary before
gaining permit approval. USGS regulations and OCS Orders ensure compliance with
Corps permit requirements. The Corps of Engineers circulates applications for
exploratory permits to various California State agencies for comment through the
Resources Agency Clearinghouse.

The Federal Water Pollution Control Act enables OCS operators to discharge
or dump into navigable waters any pollutant, brines, drilling mud, or cuttings
from drilling operations only under a permit issued by the Environmental Protec-
tion Agency (EPA). L6/ An operator must submit a discharge permit application to
EPA at least six months before he plans to begin drilling operations. EPA pub-
lishes notice of the application in a newspaper of general circulation in the
area adjacent to the proposed drilling and notifies interested federal and state
government agencies, public-interest groups, and individuals. In California, EPA
invites the State Water Resources Control Board to comment on the application.
Any group or person in California who wishes to comment on discharge permit appli-
cations should notify the EPA Regional Administrator in San Francisco.

EPA must consider all the environmental consequences, including impact on
water quality, of granting a discharge permit and may condition the permit as
necessary to prevent adverse impacts. 27/

Finally, the Coast Guard regulates lighting and markings on platforms and
floating drilling rigs, oil spilled or discharged into OCS waters, and the s.afety
of offshore operations. 28/

If oil and gas are discovered, they must be produced in paying quantities or
the lease will not be extended beyond its primary term of five years. Paying
quantities simply means production in quantities sufficient to yield an economic
return in excess of operating costs. 29/ USGS determines whether a discovery meets
this requirement.. Under current praCtice, there is no announcement when USGS makes
such a determination.

The lessee may abondon the tract or change his drilling strategy by changing
the exploratory plan if he does not make a commercial discovery of oil and gas.
If he decides to abondon the tract, the lessee must submit to the Supervisor a
statement of reasons for abondonment and a detailed plan for carrying out abandon-
ment operations, and the lessee must provide for capping and cementing the well.-30/
The Supervisor must approve the abandonment in writing, according to USGS
requirements. 31/

Oil companies sometimes undertake geophysical and qeoloqic exploratory activi-
ties after a lease sale. Depending on how many data are available from pre-lease

120

exploration, or on whether the first exploratory well on a lease tract finds
marginal or no commercially producible quantities of oil, more geophysical and
geologic information and exploratory drilling may be necessary to define the
size and location of the oil-bearing structure. Operators conduct post-lease
sale geophysical and geologic exploration under permits and conditions similar
to those required by USGS for pre-lease sale exploration.

DEVELOPMENT

Before an operator can develop an oil or gas field and commence production,
he must submit a development plan to USGS for approval. The development plan
contains the same elements as the exploratory drilling plan: (1) a description
of drilling vessels, platforms, or other structures showing the location, design,
and major features, including features pertaining to pollution prevention and
control; (2) the general location of each'well, including surface and projected
bottom-hole location for directionally drilled wells; (3) structural interpre-
tations based on available geologic and geophysical data; and, (4) such other
pertinent data as the Supervisor may prescribe. 32/

Once again, the USGS makes an environmental assessment within 30 days and
decides whether an EIS is necessary. If the Supervisor determines approval of
the development plan constitutes a major federal action signi-ficantly affecting
the environment, then state and local governments and other interested persons or
groups may comment on the environmental effects of the plan through the EIS review
process. EISs were prepared on the partial development plan for the Santa Ynez Unit
33/ and for resumption of oil and qas development in the Santa Barbara Channel. 34/

Recent amendments to USGS regulations allow states to review parts of develop-
ment plans and additional information on proposed development activities and their
anticipated impacts.35/ Thirty days before submitting a development plan to USGS,
the operator must su@_ply to the governors of directly affected states a description
of all offshore and onshore facilities and operations proposed in the plan or dir-
ectly related to the proposed development. The USGS Supervi-sor requires that
development plans specify the location, size, requirements for land, labor, materi-
als, and timing of development and operation, in addition to any other related
economic or environmental information. After the development plan goes to USGS,
the Supervisor provides to the governors of directly affected states a copy of the
development plan, except for those portions designated by the operator and approved
by the Supervisor for exclusion. USGS may withhold information that reveals:
(1) commercial and financial informationand privileged or confidential trade
secrets; or, (2) geologic and geophysical information and data maps concerning wells.

After approval of the development plan, the operator must obtain a drilling
permit from USGS and a permit from the Corps of Engineers for installation of any
platform, subsea production system, or artificial island. 36/ California State
agencies have an opportunity to review and comment on these permit applications
through the Resources Agency Clearinghouse.

Both the USGS and the U.S. Coast Guard issue and enforce safety and pollution
control regulations. 37/ In addition, the Occupational Safety and Health Adminis-
tration (OSHA) of the-labor Department has authority to enforce safety standards
on fi.xed structures on the OCS, including platforms and artificial islands. 38/

At present, there is some confusion over the division of responsibility
between OSHA and.the Coast Guard for safety of offshore operations. The Coast

121

Guard maintains its safety regulations are adequate, but OSHA claims it should
regulate working conditions on platforms, just as it does in other industrial
work places, under the explicit authority granted by the Occupational Safety and
Health Act. 39/ An incident in the Santa Barbara Channel illustrates the confu-
sion that now exists around this issue: the building contractor on Exxon's Hondo
Platform denied OSHA inspectors access to investigate employee complaints of un-
safe working conditions on the platform; the building contractor claimed that
only the Coast Guard, not OSHA, had authority to inspect working conditions on
the platform. 4,1/ This confusion would be resolved under legislation to amend
the OCS Lands Tct.that is now pending in the U.S. Congress.

TRANSPORTATION

Transportation of oil and gas from the OCS is either by pipeline or by
tankers and barges. All production in California to date and nearly all produc-
tion in the Gulf of Mexico has been transported by pipeline.

PIPELINES. There are two types of pipelines on the OCS, gathering lines
and transmission lines. Gathering lines move oil and gas from producing wells to
a central point for treatment, storage, or measurinq and terminate at the final
metering.point under USGS jurisdiction. Pipelines moving hydrocarbons beyond
this point are transmission lines.

The proposed location and design of gathering line,, are included in the
development plan which USGS must approve before development can proceed. Gather-
ing lines located entirely on one lease require no riqht-of"way easement. If a
gathering line will cross other leases, however, USGS must notify the lessees of
those tracts and grant an easement before the line is built. USGS does not require
a rental charge for theeasement since these easements are considered an extension
of lease production facilities. 41/

Oil and gas transmission lines are either common carriers or private carriers.
Common carrier lines transport oil or gas for a fee without descrimination against
any shipper. Private carriers transport oil or gas belonging to the owner(s) of'
the pipelines. BLM grants riqhts-of-way for common carrier oil or gas transmission
lines and charges rent for each pump station and for the length of the riqht-of-way
used. 421 The Interstate Commerce Commission (ICC) requlates rates for and access
to comFo-n carrier oil transmission lines. 43/ Before 'constructing a common car-
rier gas pipeline from the OCS to shore, t@_e operator must obtain a Certificate of
Public Convenience and Necessity from the Federal Power Commission (FPC). The FPC
also sets natural gas prices and transmission rates for these lines and must ap-
prove any plans to abandon a gas pipeline. 44/

All oil pipelines from the OCS in California are private carriers regulated
by USGS. Oil transported in these lines is generally metered onshore; therefore,
these pipelines are seen as an extension of a lease oneration. Private carrier
gas transmission lines, however, are treated as common carriers for most regulatory
purposes. 45/

The Corps of Engineers must issue a permit for the construction of pipelines
on the ocean, floor. 46/ For pipeline construction within the territorial sea
.0ess than three miles from shore), the Corps must issue a dredge and fill
permit. 47/ The Corps requires another permit for dumoing material dredged during
the consT-ruction and burial of the pipeline in ocean waters beyond the territorial

122

seas. -48/ The Corps circulates each of these permit applications to California
state agencies for comment through the Resources Agency Clearinghouse.

All pipelines on the OCS must meet the requirements of the Office of Pipe-
line Safety Operations (OPSO) in the Department of Transportation. 49/ OPSO
regulations apply to the design, installation, inspection, testing,-construction,
extension, operation, replacement, and maintenance of pipelines. Pipelines in
place off California's OCS are buried only near the shore to protect them from
damage by the surf. 50/ OPSO reaulations, however, now renuire burial of new
pipelines which cross shipping lanes or harbor areas, in order to Prevent damage
from anchors.

TANKERS AND BARGES. The Coast Guard establishes and administers-certifica-
tion requirements for tankers and barges. The Federal Maritime Commission super-
vises rate schedules and licensing for common carriers, tankers, and barges. 51/

Use of an offshore processing, storage, or terminal facility in connection
with transporting*oil producticn by tanker, instead of by pipeline, must be ap-
proved by USGS as part of an OCS development plan. USGS and Coast Guard safety
and pollution control regulations also apply to such facilities. In addition,
the Corps of Engineers must issue a permit for such installations, since they
pose a potential hazard to navigation. State agencies have an opportunity to
comment on the permit application filed with the Corps through the Resources
Agency Clearinghouse. EPA requires a permit for any discharge of pollutants
from offshore facilities. The California Water Resources Control Board then
comments on these permit applications.

SHIPPING LANES AND SAFETY FAIRWAYS. The Coast Guard and Corps of Engineers
have authority to establish regulatory mechanisms to prevent vessel collisions
in congested areas of the OCS and territorial sea. In congested waters, the
Coast Gua.rd may establish a Vessel Traffic Separation Scheme (VTSS) with traffic
lanes separating vessels going in opposite directions. A VTSS does not affect
the placement of platforms or floating drilling rigs. 52/ The Corps of Engineers
may establish safety fairways, however, prohibiting the installation of any fixed
structures in the fairway, including platforms or movable drilling rigs. 53/

VTSSs established in the Santa Barbara Channel and Gulf of Santa Catalina
cross many federal oil and gas lease tracts, creating a conflict between OCS oil
and gas development and shipping. In addition, the tract selection for current-
ly pending OCS Lease Sale #48 includes a number of tracts located in the vessel
traffic lanes. The Coast Guard requested the Corps of Engineers to establish a
safety fairway in the traffic lanes crossing lease tracts in San Pedro Bay. The
State of California supported the Coast Guard's request, 54/ but the BLM and the
Western'Oil and Gas Association (WOGA), an oil industry group, opposed it. 55/
The Corps has decided to allow exploratory drilling within the VTSS under q7i5de-
lines designed to minimize hazards to navigation and has deferred a final aeci-.
sion on establishing a fairway until lessees complete "substantial" exploratory
work in the area.

UNITIZATION

OCS lease tract boundaries are drawn without consideration or knowledge of
-where accumulations of oil and gas exist. A grid, superimposed on the OCS, deter-
mines tract boundaries. Oil and gas accumulations are commonly called pools or
reservoirs. Often a reservoir underlies leases belonging to two or more individual

123

owners, creating a strong incentive for each competing owner to produce rapidly
as much oil and gas as possible before the reservoir is exhausted. 56/ This
could lead to the drilling of u-nnecessary wells and a reduction in @_otal oil and
gas recovery. Production of oil and gas at a precipitate rate unduly lowers the
pressure that 'drives the oil and gas out of the reservoir, and ultimate recovery
from the reservoir is reduced. In addition, effective use of secondary and ter-
tiary recovery operations is nearly impossible where the petroleum reservoir in-
volves more than one lease tract and the owners are competing for the available
resources.

Unitization is an agreement among several lease tract owners in a prospec-
tive or producing oil and gas field, or part of a field, that provides for
development and operation of several tracts as a unit by a single operator sel-
ected from and agreed to by the lessees. Owners share proportionately the expen-
ses of the unit and ownership of the produced oil and gas. Unitization can occur
anytime after a lease sale, but it usually occurs after discovery of an oil or
gas reservoir and before development and production. 57/ Since the lease tracts
within the unit are developed and operated as though they were one, the terms of
all the leases are extended as long as oil and gas are produced in paying quanti-
ties from, or the operator conducts drilling or well reworking activities on, any
least tract within the unit area.

USGS encourages voluntary unitization and has the authority to compel uniti-
zation to conserve oil and gas or other marine resources, including marine life and
recreational and aesthetic values. 58/

PRODUCTION CONTROLS

USGS reculates the rate of production from OCS leases and units through
review and approval of the maximum efficient rate of production (MER) from oil and
gas reservoirs and the maximum production rate (MPR) from individual wells. MEP
is the maximum rate at which oil and gas can be steadily withdrawn from a reser-
voir without detriment to ultimate recovery. MPR is the approved maximum daily
rate at which oil may be produced from a specified oil and gas well. Operators
must make quarterly production reports to USGS; and if operators overproduce,
they are subject to mandatory suspension (shut-ins) of production. The USGS Super-
visor may allow an operator forced to curtail or suspend production because of
storm, hurricane, emergencies, or other conditions peculiar to offshore operations
to make up his production losses through production rates above the MER. 59/

ADVISORY BOARDS

Three groups presently advise the Interior Department on OCS oil and gas devel-
opment: the National Petroleum Council, the National OCS Advisory Board, and the
OCS Environmental Baseline Studies Advisory Committee. The National Petroleum
Council (NPC), composed primarily of oil industry representatives and a few consumer
and environmental groups, advises the Secretary of Interior on a wide range of is-
sues, including OCS oil and gas development. The National OCS Advisory Board is a
board of representatives from each of the coastal states (except Hawaii); it ad-
vises the Secretary of the Interior on all facets of offshore oil and gas policy.
The Board,is divided into six regional boards, one of which -- the Pacific regional
board -- includes representatives of California, Oregon, and Washington. Bill Press,
Director of the Governor's Office of Planning and Research, is California's repre-
sentative on the OCS Advisory Board. The OCS Environmental Baseline Studies Advisory

124

Committee is basically a technical panel, composed of representatives from the
coastal states, that advises BLM on its environmental studies program. It is
considered a committee of the National OCS Advisory Board but'actually meets and
operates quite independently of the Board. Bill Northrop, Executive birector of
the State Lands Commission, is California's representative on that board.

REPORTS AWINSPECTIONS

USGS requires OCS to submit detailed reports on their operations and produc-
tion. Operators must keep complete records of all well operations at a location
convenient to the USGS Supervisor and must provide copies of these records to the
Supervisor upon request. 6Q1 The Supervisor must also receive monthly reports
of all operations and proU-uction. 61/

Under recently revised regulations, geologic interpretations and qeophysical
data and interpretations submitted to USGS under these requirements are not availa-
ble to the public without the consent of the lessee(s) for as long as the lease
remains in effect or for ten years, whichever is less. USGS cannot release geolo-
gic data and analyzed geologic data to the public without the consent of the les-
see(s) for as long as the lease remains in effect or two years, whichever is less.
The Supervisor may release any of this data or interpretive information, with the
approval of the Directors of USGS, if he determines that earlier release is neces-
sary for the proper development of,the field or area.-62/ These disclosure pro-
visions apply only to information from leases issued aTt-er June 23, 1976. Leases
issued in Lease Sale #35 in 1975 and in the Santa Barbara Channel in 1968 are,
therefore, not subject to these provisions.

USGS inspects offshore facilities and operations and enforces regulations and
orders. In the Santa Barbara Channel, USGS has eight inspectors to inspect five
producing platforms, floating drilling rigs, jack-ups, and two onshore facilities
that receive production from the platforms. There, are daily inspections of opera-
tions in the Dos Cuadras fie 'ld (Platforms Hillhouse, A, and B), and weekly inspec-
tions in the Carpinteria field (Platforms Houchin and Hogan). Floating drilling
rigs or jack-up drilling rigs that have been out of service for some time and are
new to the Pacific area receive a comprehensive inspection by USGS before they com-
mence drilling. After normal drilling begins, USGS conducts inspections at least
once a week. USGS inspectors witness all operations or tests considered cri.tical
or non-routine that occur on productinn platforms, floating drilling rigs, or jack-
up rigs. Processing of all oil and gas-.now produced from the OCS takes place at
the Phillips La Conchita blant or the Mobil Sea Cliff plant. Both plants are near
Rincon Point and are inspected weekly by USGS. 63/

Each onshore and offshore facility receives a comprehensive inspection by USGS
every six months. All equipment must conform to USGS regulations and OCS ord rs.
Operators face specific enforcement actions for "incidents of,noncompliancel.1 ?INC).
Depending on the hazard presented by a particular INC, the operator may receive a
warning and seven days to correct the INC. For more serious.INCs, USGS may order
the operator to shut-in the affected equipment or the entire platform, drilling
rig, or onshore facility. Lessees are subject to loss of lease, imprisonment, or
a fine for noncompliance with regulations or OCS orders, but USGS has never invoked
this penalty in the Pacific OCS to date. 641 In addition to facility and opera-
tions inspections, the public may examine'inspection records at the Ventura and
Los Angeles offices of the Conservation Division of USGS. 65/

125

A S U M M A R Y 0 F F E D E R A L S T A T U T E .S
A N D A G E N C Y R E S P 0 N S I B I L I T I E S
E L A T I N G T 0 0 C S D E V E L 0 P M E N T

This section summarizes the federal laws relevant to offshore oil and qas
development and the major roles of federal agencies in OCS activities as of March,
1977. The Carter administration and several members of Congress have proposed a
number of changes in the leasing and management system, however, includinq amend-
ments to the OCS Lands Act and a division of responsibility for leasinq and
developinq offshore lands between the Interior Department and a new Department of
Energy. Laws and responsibilities summarized below may change as the result of
new legislation or ,@xecutive or administrative actions.

FEDERAL STATUTES RELEVANT TO OFFSHORE OIL AND GAS DEVELOPMENT

Anadromous Fish Conservation Act. 16 U.S.C. 757. This Act authorizes the
Secretary of the Interior to enter into cooperative agreements with states to
conserve anadromous fishes. Federal monies are available to help reduce harm to
the anadromous fishery resources of the coastal states from offshore development.

Clean Air Act Amendments of 1970. 42 U.S.C. 1857-1857f. The Clean Air Act
sets general guidelines and minimal air quality standards on a nationwide basis.
States are responsible for developing comprehensive olans for all regions within
their boundaries. The requirements of the Act and state orograms apply to any
OCS-related facility or activity onshore or within the three-mile-wide territorial
sea, but it is unclear whether the Clean Air Act operates to reaulate air quality
offshore beyond three miles.

Coastal Zone Management Act of 1972. 16 U.S.C. 1451-1464. The Coastal Zone
Management Act (CZMA) provides federal fundinq to states to assist them in.develop-
ing and administering their own coastal zone management Drograms. Amendments to
the Act enacted in 1976 created a program to compensate states for the onshore
effects of the location of coastal-dependent energy facilities. Once a state has
devised a federally approved coastal zone management plan, the Act requires federal
agencies conducting or supporting activities directly affecting the state's coastal
zone to do so in a manner consistent to the maximum extent practicable with the
state's plan. Furthermore, activities requirina a federal license or permit affect-
ing land or water use in the coastal zone must be consistent with an approved state
plan or be otherwise necessary for the national security. Lastly, the CZMA author-
izes federal grants to states of up to 50% of the cost of acquiring, developing,
.and operating estuarine sanctuaries.

Commercial Fisheries Research and Development Act of 1964. 16 U.S.C. 779-779f.
This Act authorizes the Commerce Department to make federal funds available to
states to research and develop commercial fisheries in areas affected by offshore
development.

Department of Transportation Federal-Aid Highway Provisions. 23 U.S.C. 138,
317. Under this Act, the Secretary of Transportation must cooperate with various
federal agencies and with the states in developing transportation plans and programs
that include measures to maintain and enhance the natural beauty of the lands tra-
versed. Roads servicing OCS-related onshore facilities that cross federal lands
or were built with federal aid must comply with these provisions.

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Federal Water Pollution Control Act Amendments of 1972 (FWPCA). 33 U.S.C.
1251 et pe. The Federal Water Pollution Control Act Amendments (FWPCA) limit
and c6-n-t ro the discharge of oil or other hazardous substances into the sea. The
FWPCA applies,only to offshore facilities and vessels within 12 miles of shore.
A permit from EPA is required if.these activities result in discharges into the
water.

Fish and Wildlife Act of 1956. 16 U.S.C. 742a-754. This Act established
the United States Fish and Wildlife Service in the Interior Department to study,
protect, and manage fish resources. The Secretary of the Interior must investi-
gate all changes or diminution in the number of food fishes of the coastal waters
and report to the Congress his recommendations for actions to protect fish in
these areas.

Fish and Wildlife Coordination Act. 16 U.S.C. 661-6673. This Act authorizes
the Secretary of the Interior to assist government and non-government organiza-
tions in the protection of all species of wildlife and requires notification of
the Department of Commerce if a particular offshore development harms wildlife.

Fish Restoration and Management Projects. 16 U.S.C. 777-777k. Federal
funds for the management and restoration of fisheries are available from the
National Oceanic and Atmospheric Administration.of the Commerce Department under
the authority of this Act.

Intervention on the High Seas Act. 33 U.S.C. 1471-1487. The Intervention
on the High Seas Act gives the Secretary of Transportation reSDonsibility.to take
those measures necessary to protect the United States' marine resources, wildlife,
coastal zone and estuaries, and shorelines and beaches against polluting oil
discharqes from ships on the high seas. The Secretary may coordinate all efforts
to eliminate the threatened pollution and remove or destroy the ship and cargo
creating the danger, if necessary. This Act derives authority in international
law from the Convention Relating Intervention on the High Seas in Cases of Oil
Pollution Casualties, opened for signature November 29, 1969; T.I.A.S. 8068. The
law pertains to all.ships on the high seas except warships and other ships owned
by foreign governments engaged in noncommercial service.

Marine'Mammal Protection Act. 16 U.S.C. 1361, 1362, 1371-1384. This Act
prohibits the taking of pinnipeds in offshore waters.

Marine Protection, Research, and Sanctuaries Act of 1972. ("Ocean Dumping
Act") 33 U.S.C. 1401-1444. This Act authorizes the designation of marine sanctu-
aries by the Secretary of Commerce with the approval of the President. Also under
the Act, the Environmental Protection Agency regulates the dumping of materials in
the territorial sea, contiguous zone, or ocean waters.

National Environmental Policy Act of 1969 (NEPA). 42 U.S.C. 4321-4347. NEPA
sets national policies to protect the environment and create and maintain conditions
under which man and nature can exist in productive harmony. The Act requires
federal agencies to prepare and consider an environmental impact statement before
taking any major action that could significantly affect environmental quality,
including offshore oil and gas leasing and development.

National Historic Preservation Act. 16 U.S.C. 470 et seg. The National
Pistorical Preservation Act protects historical and cultural resources, including

127

those on offshore lands. Mandatory procedures for protecting these resources
appear in 36 C.F.R., Part 800, under the authority of Executive Order 11593
and this Act.

Natural Gas Act. 15 U.S.C. 717-717w. The Natural Gas Act authorizes the
Federal Power C05mmission (FPC) to regulate natural gas pipelines engaged in inter-
state commerce, including those transporting gas produced from the OCS.

Natural Gas Pipeline Safety Act of 1968. 49 U.S.C. 1671-1684. The Depart-
ment of Transportation sets and enforces standards for the design, installation,
inspection, testing, construction, and maintenance of natural gas pipelines, in-
cludinq those on the OCS, pursuant to this Act.

Occupational Safety and Health Act of 1970 (OSHA). 29 U.S.C. 651-678.
OSHA authorizes the Secretary of Labor to set and enforce mandatory occupational
safety and health standards for work places. The Act specifically applies to
OCS activities.

Oil Pollution Act Amendments of 1973. 33 U.S.C. 1001-1015. This Act pro-
hibits the discharge of oil or oily mixtures from ships within 50 miles of land
except in certain specific instances. The Act outlines sections of the Inter-
national Convention for the Prevention of the Pollution of the Sea by Oil (1954).
Small discharges from ships'en route to the coast are exempt.

Outer Continental Shelf Lands Act. 43 U.S.C. 1331-1343. The OCS Lands Act
of 1953 established the jurisdictio the United States federal government over
mineral resources of the Outer Continental Shelf beyond the three-mile territorial
limit. State laws consistent with the Act apply to the OCS. The Act gives the
Secretary of Interior authority to lease OCS tracts by competitive bidding and
provides general guidelines and directives for managing the exploration, develop-
ment, and production of the oil and gas resources. The Coast Guard regulates the
safety of offshore activities and shares responsibility with the U.S. Army Corps
of Engineers for insuring safe navigation under the Act.

Ports and Waterways Safety Act of 1972. 33 U.S.C. 1221-1227. This Act
authorizes the Department of Transportation to establish vessel traffic service
and systems for ports, harbors, and other waters subject to congested vessel traffic.

Submerged Lands Act. 43 U.S.C. 1301-1315. The Submerged Lands Act qrants
coastal states exclusive rights to the resources of offshore lands up to three
geographical miles from the shoreline. Federal rights and powers relating to
navigation, commerce, national defense, and international affairs within the three-
mile territorial sea are retained by the federal government and not affected by
this law.

Wildlife Restoration. 16 U.S.C. 669-669i. Federal funds are available to
states under this Act for wildlife restoration projects.

OCS RESPONSIBILITIES OF FEDERAL AGENCIES
Department of Commerce National Oceanic and Atmospheric Administration (NOAA).
Several offices within the National Oceanic and Atmospheric Administration have
OCS-related responsibilities: Office of Coastal Zone Management (marine sanctu-
aries and copstal zone management); National Marine Fisheries Service (commercial

128

fisheries and other living marine resources); Environmental Data Service (OCS
marine environmental assessment data management)-,' National Ocean Survey (tides,
currents, and other environmental features affecting the design and.location of
offshore structures); National Sea Grant Program (marine research funds);
Environmental Research Laboratory (assessment study of petroleum development on
the Alaskan OCS); and, the National Wildlife Service (historic storm data,
weather forecasts, and hurricane warnings). All federal agencies must notify
the Department of Commerce National Oceanic and Atmospheric Administration of
any proposal to grant a license or permit that might affect marine life and
habitats. NOAA provid -es meteorological, oceanographic, fisheries, and marine
wildlife data to other agencies for,assessments of environmental impacts and
recornmends mitigating conditions for protection of marine and coastal resources.
In addition, NOAA assists the Department of Interior in the conduct of environ-
mental baseline studies.

Department of Defense Corps of Engineers. The U.S. Army Corps of Engineers
has responsibility for preventing obstructions to navigation on the OCS. The
Corps issues permits and sets and enforces regulations for fixed offshore struc-
tures, including platforms, artificial islands, pipelines, and exploratory drill-
ing vessels. In congested areas, the Corps of Engineers has authority to estab-
lish safety fairways within which the installation of permanent structures is
prohibited.

Environmental Protection A_qency _(EPA The Environmental.Protection Aqenc.y
has responsibilities for preventing and reducinq air and water pollution. EPA
sets national ambient air quality standards for air pollutants and reviews state
implementation plans designed to achieve-those standards. EPA's air pollution
controls apply to onshore facilities related to offshore petroleum development
and could directly affect offshore operations. EPA issues permits for the dis-
charge of pollutants into offshore waters and works with the Coast Guard to.cary@y
out a national oil spill prevention and cleanup program.

Executive Office of the President/Council on Environmental Quality (CEO).
CEQ advises the President on matters affecting the environment. CEQ establishes
guidelines for the preparation of environmental impact statements under the
National Environmental Policy Act and annually publishes.substantive analyses of
various environmental issues, including OCS oil.and gas development.
Federal Power Commission (FPC). The FPC regulates the price and transportation
of natural gas in interstate commerce, including all gas produced from the OCS.
The Commission issues permits for the construction and operation of OCS and
other interstate gas pipeline and storage facilities used with such pipelines,
sets the wellhead price of OCS gas, and must ass'ure the nondiscriminatory trans.-
portation and purchase of natural gas.

Interstate Commerce Commission (ICC). The ICC regulates rates and acce'ss
to common carrier oil pipelines in inte ate commerce, including oil pipelines
from the OCS.

Department of the Interior/Bureau of Land Management (BLM) BLM has respon-
sibility for leasing offshore lands and Follecting lease bonuses and rents. In
administering lease sales, BLM receives nominations and selects tracts for inclu-
sion in the sale; prepares an environmental impact statement for each sale, makes
an economic, engineering, and geologic evaluation of tracts to be leased; and

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receives bonus bids and determines whether to award leases to the highest bidd6rs
on individual tracts. BLM also grants rights-of-way for oil and gas transmission
lines from the.OCS to shore.

Department of the Interior/Fish and Wild life ServicP. The Fish and Wildlife
Service provides biol@_gicalassistance and recommendations for lease stipulations
to BLM and USGS for OCS leasing and development activities pursuant to Secretarial
Order 2974 dated April 30, 1975.

Department of the Interior/United States Geological Survey (USGS). Before
BLM leases offshore lands, the USGS makes broad area surveys to assess hydro-
carbon potential, grants permits for the conduct of geophysical and geologic
exploration, participates in the preparation of environmental impact statements
on proposed lease sales, and advises BLM on the resource potential and dollar
value of specific lease tracts. USGS has the primary responsibility for super-
vising exploration, development, and production activities on OCS leases. This
post-lease supervision includes issuing and enforcing safety regulations, issu-
ing geophysical and geologic exploration permits, reviewing exploration and
development plans, issuing drilling permits, granting rights of use and easements
for OCS pipelines on the OCS, and collecting royalties.

Department of Labor/Occupational Safety and Health Administration
In conjunction with the Department of Health, Education, and Welfare (HEW), HSA
sets safety and health standards for fixed structures on the OCS. OSHA conducts
inspections at the request of employers or workers and enforces the safety and
health regulations.

Department of Transportation/Coast Guard. The Coast Guard has several
responsibilities for safety and the prevention of pollution on the OCS. The
Coast Guard establishes and enforces safety regulations for platforms and other
fixed structures, -insures proper marking of platforms to nrevent collisions with
vessels, and inspects floating drilling rigs. The Coast Guard enforces federal
oil pollution laws in both federal and state waters offshore, shares responsi-
bility with the Environmental Protection Agency for oil spill prevention and
cleanup, and coordinates the National Oil and Hazardous Substance Pollution Con-
tingency Plan. In congested waters, the Coast-Guard may establish a voluntary
Vessel Traffic Separation Scheme (VTSS) such as those established in the Santa
Barbara Channel and Gulf of Santa Catalina, with traffic lanes separating vessels
going in opposite directions. In establishing such a scheme, the Coast, Guard has
no authority over the drilling operations of floating drilling,rigs or the place-
ment of platforms. These facilities and operations fall under the U.S. Army
Corps of Engineers' or U.S. Geological-Survey's authority to regulate the loca-
tion of fixed structures on the OCS.

Department of Transportation/Office of Pipeline Safety. The Office of
Pipeline Safety issues and enforces regulations apolying to the design, instal- 4L
lation, inspection, testing, construction, extension, operation, replacement,
and maintenance of natural gas and petroleum pipelines crossing state lines,
including OCS pipelines. This jurisdiction includes transmission pipelines,
offshore gathering lines, and onshore gathering lines in nonrural areas.

I M P R 0 V,I N G M A N A G E M E N T 0 F 0 C S R E S 0 U R C E S

As established by the Outer Continental Shelf Lands Act of 1953, the stated
goals of the federal OCS leasing and management program are: (1) to promote

130

orderly and timely resource development; (2) to protect the environment; and,
(3) to assure the receipt of a fair market return for the public's resources.
These are fitting goals, but to date the structure of the federal leasing and
management system has hampered the development of policies to achieve these
goals. The present system also frustrates efforts by state and local qovern-
ments to participate in the process. Within the federal government an@ within
the state government of California, coordination among agencies involved in OCS
issues needs improvement.

DECIDING TO LEASE

The decision to lease an OCS tract is fundamental. Because federal oil and
gas leases presently convey rights to develop and produce oil and gas found in
commercial.quantities, a lessee will develop@a tract if he discovers sufficient
oil and gas to economically justify development.

Estimates of the resources underlying lease tracts are key factors in leasinq
decisions. Inferences about the q6oloqy of prospective areas drawn from seismic
surveys and samples of rock outcroppings from the ocean floor serve as a basis for
these resource estimates. If BLM proposes to lease an area adjacent to already
leased tracts, well data from these tracts can supplement information from seismic
surveys and rock samples taken in the unleased areas. Although these data make it
possible to identify geologic structures that may contain oil or gas, as well as
estimates of their hydrocarbon potential, the.on'@y wav to know if oil and qas are
in fact present and to assess the size and characteristics of the reservoir is to
drill an exploratory well. The current leasing system does not provide for eXDlora-
tory drilling until after a tract is leased. Thus, pre-lease'resource estimates
are necessarily speculative. Leasing on the basis of speculative estimates without
direct information on the presence of oil and gas hampers efforts to achieve the
goals of the federal OCS program.

TIMELY AND ORDERLY DEVELOPMENT. The need to lessen the nation's dependence
on foreign sources of oil and gas has given the goal of timely and orderly develop-
ment of OCS resources special urgency. To increase domestic fuel supplies from
the OCS, we must explore for oil and qas and bring what we find into Droduction as
rapidly as possible, without sacrificing the environment or giving away the publi-c's
resources at less than a fair market price.

Speeding exploration of the OCS currently requires accelerated leasing because
the Department of the Interior does not permit exploratory drillinq@on tracts
before-they are sold. Leasing conveys development and production rights in addition
to exploration rights for a tract. This automatically commits to development any
leased tract containing commercial nuantities of oil and gas. This commitment to
develop large areas of the'OCS without direct information on the presence of Oil
.and gas prevents the federal government from pursuing leasing strategies that con-
centrate industry efforts in the most promising areas.* The result is exploration
and development of the OCS at a rate and in a manner that meets the individual
business management needs of various oil companies, irrespective of overall OCS
planning and management goals-.

FAIR MARKET RETURN. Calculating minimum acceptable bids for tracts Is dif-
ficult without Tirect information on oil and-gas resources because geophysical and
qeologic data presently available before exploratony,dri.lling are subject to wide
differences in interpretation. Large variations in bids among oil -companies and
the valuation of the USGS for specific tracts demonstrate the-degree-of uncertainty
associated with determining tract values.before a.lease sale..
10--76658 131

For example, USGS's pre-sale value on Tract #76 in Lease Sale #35 off
southern California was $24,543,360. This tract received a high bid of t5,276,160.
After the sale, USGS reviewed its original valuation for this tract and assigned
it a new value of $144,000. This is the minimum offer the Interior Department
will accept on any OCS tract offered for sale anywhere and reflects a judgment
by USGS that the.tract contains no resources or an insufficient amount for a
lessee to make a profit. The hiqh bid for Tract #76 was accepted. 66/

If competitive market conditions exist, the federal bonus bidding system
should provide a fair market price for the public's resources. In southern
California Lease Sale #35, however, there appeared to be a lack of competition,
possibly attributable to the accelerated leasing rate in the last few years. In
Lease Sale #35, only 70 tracts received bids out of 231 offered for sale. Out
of those 70 tracts, 40 received one bid and nine received two bids. Of the 56
tracts leased, 30 had one bid and six had two bids. 67/

Both the oil industry and the federal government can make educated guesses
about the oil and gas potential of tracts; but before the lease sale, neither
government nor industry knows how much oil and gas is present or even whether it
is present at all. Federal OCS leasing is essentially a gamble for both industry
and government. One cannot know the actual quantity of recoverable oil and gas
in a reservoir until it is produced, but a much better estimate of the recoverable
-resources is possible with direct information from exploratory drilling than with-
out it.

ENVIRONMENTAL PROTECTION. One of the ways in which the Interior Department
seeks to protect the environment is to delete tracts where develonment would be
environmentally harmful from the list of tracts offered at lease sales, or to
offer such tracts for sale subject to special conditions (lease stipulations).
Decidinq whether to offer tracts for sale or to offer them under special condi-
tions is especially difficult where the environmental risks and resource potential
are closely balanced, since the only resource estimates available under the present
system are so speculative and imprecise.

Although a memorandum of understanding on tract selection procedures between
BLM and USGS requires USGS to include a tract-b.v-tract resource estimate in the
joint BLM-USGS tract selection recommendations sent to Washinqton by the field
offices of the two bureaus, 68/ USGS officials recently told the U.S.. General
Accounting Office (GAO) that this information has never been provided for any OCS
sale. Furthermore, the USGS officials told GAO they did not believe collecting
sufficient information to make such an estimate so early in the leasing. process
is worthwhile. LV

BLM's Pacific OCS Office Manager, Bill Grant, asked USGS to estimate the
quantity of oil or gas per acre for each tract under consideration for Lease Sale
#35. Sufficient geologic information did not exist within government or the oil
industry to make such an estimate, but USGS did not attempt to obtain the data
on its own. Instead, USGS compared onshore basins and oil fields with unexplored
areas offshore that exhibit similar geologic characteristics. This process pro-
duced estimates of areas comprised of many tracts, without any indication of how
those resources might be distributed among the tracts. Z0_/

When balancing the resource potential of specific tracts proposed for sale
in Lease Sale #35 against the environmental risks of leasing and developing those

132

tracts, Interior Department officials had only speculative resource estimates for
thegeneral areas in which the tracts were located.

PRE-LEASE DRILLING. In order to improve the quality of resource information
for making tract selection decisions, the Interior Department should acquire direct
information from exploratory,drilling to make tract-by-tract oil and gas resource
estimates before lease tracts are offered for sale. In some areas in southern
California, direct information-will be available from a well or wells drilled on
a leased tract into a geologic structure that also underlies an unleased tract or
from core wells drilled off southern California before the federal-state boundary
was finally established. The state of California should work out an arrangement
with the federal government to make information from drilling in state lands
available to USGS for use in making resource estimates. In instances where direct
information on geologic structures underlying a tract under consideration for
leasing is not otherwise available, at least one test well should be drilled on
those structures before those tracts are offered for lease.

This drilling should be carried out in the same manner as deep stratigraphic
test wells are now drilled before lease sales: the wells should be drilled by
groups of private companies sharing the costs of the wells and the data from them.
These groups should be privately organized, and select the location of the well.
Approval of the well location and a drilling permit from USGS should be requi.red
before the well could be drilled. As a condition of the permit, information from
the test well should be made available to USGS' Companies not participating in the
group when the well is drilled should be allowed to buy the well data only after
paying a proportionate share of the well costs plus a substantial penalty.

A limited pre-lease drilling program should provide substantially better
resource information for making tract selection decisions than is available under
the present leasing system. Before drilling, the only information available for
making resource estimates is-geonhysical data from magnetic, seismic, and gravity
surveys, data on the surficial geology, and data from deep stratigraphic wells
deliberately drilled at locations designed to prevent the discovery of oil and
gas. In most cases, these data will only permit the identification of structural
features and faults and help define the characteristics of the sedimentary basin.
Estimates of recoverable resources based on these data depend on assumptions about
the physical characteristics of the hydrocarbon reservoir, the quantity of hydro-
carbons present, and the physical properties of the hydrocarbons. Once an explora-
tory well is drilled at a location selected for the purpose of producing the most
information, the presence of,hydrocarbons and the reservoir'intervals can be
established, the porosity of the rock can be ascertained, the pressure of the
reservoir can be checked, and the fluid saturation can be measured. With compli-
cated tests, it is'possible to analyze the chemical and physical properties of
the hydrocarbons and the drive mechanism of the field. In addition, geophysical
information can be related to the known geology at the point the well is drilled.

One persistent question is how much drilling is enough to evaluate a prospec-
tive oil and gas.field adequately. The oil industry can point to numerous examples
where a large discovery was made only after many wells were drilled in unsuccess-
.ful attempts to find oil or gas and most companies had abandoned the area. Drill-
ing one well or a few wells on a geologic structure cannot give sufficient infor-
mation to make a definitive estimate of the resource potential of that structure,
but that is not the purpose of the pre-lease drilling program recommended here.

133

The business community fears that federally sponsored pre-lease exploratory
drilling will lead to nationalization of the oil and gas industrv. However, a
pre-lease exploratory drilling program would change the government role in the
leasing system very little. The Department of the Interior will select tracts
for lease sales basedon whatever estimates of resource potential are available.
The fact that these tract selection decisions by the Interior Department have
determined, and will continue to determine, which OCS tracts the oil industry
will have the opportunity to lease, explore, and develop would not be changed by
the initiation of the pre-lease drilling program proposed here. This program is
designed to give the Secretary of the Interior substantially better founded
estimates of resource potential than he now has when making tract selection
decisions. The pre-lease drilling program recommended here would not increase
the involvement of the federal government in deciding which OCS tracts will be
leased and developed, but it would enable the federal government to make more
informed leasing decisions.

Moreover, this pre-lease drilling proposal maintains the important role the
oil industry plays in OCS exploration. The federal government would not conduct
or finance exploratory drilling. A limited number of exploratory wells would be
drilled before leasing by a group of private companies in the same manner that
deep stratiqraphic wells are drilled under current procedures. A drilling permit
from USGS would be required, but a USGS drilling permit is also required under
existing procedures for any exploratory well drilled after a lease sale. Nearly
all of the exploratory work would be conducted, just as it is under current pro-
cedures, by private companies after the lease sale.

It is possible that the capital available to the oil industry to explore and
develop the OCS and other energy sources may be increased by a pre-lease drilling
program. Large sums are currently paid by the oilindustry in cash bonuses for
rights to explore for and produce oil and gas from the OCS with little assurance
.of a return on the investment. It is a very risky investment. For example, a
group of oil companies headed by Exxon U.S.A. paid cash bonuses totalling $632
million for six tracts in the Oulf of Mexico off the coast of Florida. Since
July 1974, eight dry holes have been drilled on these tracts. In other areas,
the oil industry has discovered large quantities of oil and gas on tracts thought
to have a relatively low potential. Some argue that the federal government has not
received a fair market return from the oil companies for the Dublic's resources
under the existing system. Regardless of who wins that argument, if the federal
government has, in fact, received a fair return, it has been due to the happen-
stance that the industry's drilling program may enable the oil companies to make
better informed bids for OCS tracts and thereby lessen the chances of a windfall
for either the government or the industry. The federal leasing system should be
designed to recover a fair return for the public's resources, not a windfall'.

This pre-lease drilling program need not cause undue delays in the delivery
of oil and gas from OCS lease tracts as long as the oil companies work diligently
in good faith with the Interior Department to implement it. In many cases, wells
drilled before leasing should allow post-lease exploratory drilling programs to
proceed more rapidly than they do now. The important thing is to increase explora-
tion of the OCS and production of offshore oil and gas without sacrificing good
management practices and abandoning the basic goals of the OCS leasing and develop-
ment program, not to see how quickly proprietary rights to OCS oil and gas can be
transferred from the government to the oil companies.

134

CONTROL OF DEVELOPMENT AFTER LEASING

The Secretary of the Interior's authority to control offshore development
after leasing is limited by the provisions of the Outer Continental Shelf Lands
Act and court interpretations of that Act. Ll/

REGULATORY AUTHORITY. As noted above, the Secretary of the Interior is
authorized to prescribe such rules and regulations as may be necessary to carry
out the provisions of the Act. The Secretary may also prescribe and amend, at
any time, such rules and regulations as he determines to be necessary and proper
in order to provide for the prevention of waste and the conservation of the nat-
ural resources of the OCS. New or amended rules or regulations issued for these
purposes-apply to all operations conducted under leases issued or maintained
under the Act. 72/

New or revised regulations apply to leases issued before the effecti 've date
of the regulations only when those regulations are issued for the prevention of
waste and conservation of the natural resources of the OCS. The courts have
interpreted the phrase "natural resources of the OCS" broadly, to include "marine
life, recreational potential, and aesthetic values, as well as the reserves of
gas and oil." 73/
@roblems arise, however, when new regulations are issued or revised for a
primary purpose other than conservation of the natural resources of the OCS or
the prevention of waste, as in increasinq safet 'v or enhancing the role of state
and local aovernments in the OCS leasing and development process. It is arguable
that allowing coastal states to review and comment on development plans and re-
leasing geologic and geophysical data and information will result in the conser-
vation of the natural resources of the OCS, but the interior Department has, in
fact, applied regulations issued for these purposes only to leases issued after
the effective date of the regulations.
Congress should amend the OCS Lands Act to permit the Secretary of the Interior
to prescribe and amend at any time such rules and regulations as he or she deter-
mines to be necessary and proper for the purposes of the Act and to apply such rules
and regulations to all operations conducted under leases issued or,maintained under
the provisions of the Act. There is no apparent reason why the Secretary's power
to issue and revise regulations and apply them to existing leases should be limited
to changes for the conservation of the natural resources of the OCS or the preven-
tion of waste, and this limitation would be removed by amending the OCS Lands Act.
To protect the legitimate and vested proprietary rights of lessees, however, leases
should not be subject to forfeiture or cancellation for the violation of regu.lations
.not in effect on the date the lease was issued. Regulations applied t6 leases
issued before the effective date of the regulations should be enforced on those
leases by strong penalties.

CANCELLATION OF LEASES. As explained above, a lease producing oil or gas
or both may,be forfeited cancelled under existing law whenever owners of leases
fail to comply with any of the provisions of the OCS Lands Act, or of the lease, or
of the regulations issued under the authority of the OCS Lands-Act and in effect
when the lease was issued. 74/ The Secretary of the Interior may cancel 1-eases not
producing hydrocarbo__n_s_-wT@enj_v_er owners fail to comply with the Act, the regulations,
or the lease and such failure continues for a period of thirty days after the
-mailing of a registered letter to the lease owner notifying the owner of the viola-
tion. 75/ A lease cannot be cancelled for the violation of regulations issued or
modifij-d after the issuance of the lease, although any person who knowingly and

135

willingly violates such a regulation may be found guilty of a misdemeanor and
punished. 76/ The Secretary may cancel any lease obtained by fraud or misrepre-
sentation.

In most instances, existing provisions are adequate for the purposes of
the OCS leasing and development program and equitable to both the public and the
oil industry. Difficulties arise, however, in two situations: 1) where risks to
human life, property, mineral deposits, or the environment which were not known
at the time the lease was issued are disclosed during the conduct of oil and gas
operations under a lease; or, 2) where a tract on which oil and gas operations pose
a high risk to the environment is leased because of a high resource estimate that
is found to be overoptimistic after exploratory drilling. The Secretary of the
Interior may decide the risks of continuing operations in either case outweigh the
immediate national interest in exploring and drilling for oil and gas, but the
'Secretary's authority to stop operations is limited under existing law.

In these situations, the Secretary may cancel the lease only if continued
operations will violate the provisions of the OCS Lands Act, or of the lease, or
of the regulations in effect when the lease was issued. Otherwise, the Secretary
can only act to suspend operations. temporarily by issuing an order or regulation
in the interest of conservation. 78/ Such a suspension must be temporary in nature,
not so open-ended as to constitufe-a virtual cancellation of the lease owner's
vested rights to develop and produce oil and gas. 79/ "A suspension whose termina-
tion was conditioned on the occurrence of events or-The discovery of new knowledge
which can be anticipated within a reasonable period of time would be a valid
exercise of the Secretary's regulatory power, and not a fifth amendment taking." 80/
The violation of rules, orders, and regulations issued after a lease has been
executed is not a ground for cancellation of a lease. L11
A regulation could, conceivably, be drafted that would enable the Secretary
to cancel leases issued after the effective date of that regulation if either of
these two situations occurs. That would have an inequitable result, however,
because the Secretary could not compensate lease owners under existing law for
the loss of their rights. Lease owners could lose millions of dollars in bonus
bids and exploration and development costs through no fault of their own. 82/
A better approach would be to amend the OCS Lands Act to give the Secretary
of the Interior authority to cancel any lease at any time when continued activity
under that lease would cause serious harm or damage to any human life, to property,
to any mineral deposits, or to the marine, coastal, or human environment. Such
damage or harm should be required to outweight the benefits of continuing activity
under the lease and be of a type that would not decrease over a reasonable period
of time. Lessees whose leases are cancelled should be paid equitable compensation,
based on all their costs, less any revenues they may have already received from
production. They should not be compensated for anticipated revenues from future
production.
In those instances where tracts are thought to have high oil and gas potential
and to have high environmental risks from development and production activitiess
the Secretary of the Interior should have the discretion to offer leases for these
tracts that grant exploration rights and make development and production rights
subject to a determination by the Secretary that production benefits outweigh all
other costs, including environmental costs. Lessees would receive the right to
drill for oil and gas, and would receive development and production rights if the

136

Secretary decides development should proceed. The most reasonable time for the
Secretary to make this decision is when the development plan is reviewed. Because
of the limited and conditional nature of the rights granted with these leases,
some bidding system other than cash bonus bidding should be used for leasing these
tracts.

LEASE TERMS. The Interior Depart ment has little real control over how rapidly
exploration and development occur on the OCS because leases are currently issued for
a primary term of five years or for as long as oil and gas are produced in paying
quantities or the lessee conducts well drilling or well reworking activities.. The
five-year primary term allows unnecessary delays.

Industry has demonstrated its ability to begin drilling shortly after lease
sales. Exploratory drilling began in the San Pedro Bay within s,even months of
Lease Sale #35. In the Santa Barbara Channel, a commercial find on the Dos Cuadros
field was announced within six weeks of the lease sale and Platform A was installed
and producing oil in less than one year after the sale.

The five-year primary term also frustrates efforts to consolidate facilit 'ies
required to transport and process OCS oil and gas by allowing exploration and
development to proceed at significantly different rates on tracts sold at the same
time in the same areas.

Congress should change the Primary term of OCS leases from five to three years,
through amendments to the'OCS Lands Act. All that is required for extending
the lease beyond the primary term is that well drilling activities be underway, and
three years is ample time for operators to begin exploratory drilling if they are
sincerely interested in developing offshore oil and gas in a timely manner. The
Secretary of the Interior should be given the discretion to offer leases with longer
primary terms in areas where extreme weather conditions prevail, in deep water to
encourage advances in offshore technology, or where other extraordinary conditions
would justify it.

INCENTIVES FOR TIMELY EXPLORATION. Lease owners must Pay annual
rents of ten dollars per acre in areas proven to hold oil and gas deposits and
three dollars per acre in unproven areas on lease tracts without commercial discov'_
eries. There is no evidence whether these rents, which come to $57,600 in proven
areas and $17,280 in unproven areas, are effective incentives to early exploration.
By comparison, the Netherlands charges low rents under its exploration licenses in
the North Sea, but the rental rate increases over time. In addition, licensees are
required to spend a minimum sum each year in exploration efforts and to give up
their rights to explore portions of the area covered by their license at specific
times. 83/ Rents collected under British and Norwegian production licenses also
increase-over time, but these rentals can be deducted from royalty payments after
production begins. 84/

The present system in the United States of charging a flat and unchanging rent
on unproductive OCS leases should be examined by the Congress and the Interior
Department to see if other mechanism&, such as a progressive rental schedule, a
mandatory work program, or a requirement that a portion of the leased acreage be
surrendered back to the government after a specified time would provide more
efficient incentives for rapid exploration and development.

137

CALIFORNIA'S ROLE IN OCS POLICY MAKING

The current leasing system provides the state and local governments of Cali-
fornia many opportunities to comment on proposed leasing and development activities
but gives them little control over these activities. Although offshore oil and gas
development will continue in state-controlled submerged lands, most new development
will occur on federal OCS lands beyond the three-mile limit of California's juris-
diction. Federal policy determines the timing, size, and location of lease sales
on the OCS; and federal agencies regulate industry exploration, development and
production. OCS oil and gas development plans may include onshore facilities
subject to state and local controls, but those facilities may also be built in
federal waters offshore -- beyond state and local jurisdiction. Hydrocarbon
emissions, oil spills, and economic and social impacts, however, do not recognize
jurisdiction lines. The manner in which offshore development takes place will
determine its effects on California, but the state and local governments of Cali-
fornia can only comment on proposed leasing and development plans and hope that
their concerns will be reflected in the decisions of federal officials. California
and other coastal states may gain some control over OCS oil and gas development
through the consistency provisions of the Coastal Zone Management Act, as amended, 85/
but the effectiveness and extent of those provisions is very uncertain.

National policy should not be subservient to one region's concerns, but the state
and local governments of California do have legitimate interests in OCS leasing and
development. There is a national interest in minimizing air pollution, potential
damage from oil spills, and damage to wildlife from oil and gas related activities
off southern California; but the people who live in southern California naturally have
a special concern because they are directly affected.

Congress should amend the OCS Lands Act so that state and local concerns will
be effectively voiced within the leasing and development process. The Secretary of
the Interior should be required to accept the recommendations of an affected coastal
state's governor on the five-year leasing schedule, a proposed lease sale, explora-
tion plan, or development plan unless the Secretary determines that the governor's
recommendations are not consistent with national security or the overriding national
interest. In doing so, the Congress must take care not to weaken the consistency
provisions of the Coastal Zone Management Act, as amended, regardless of the
uncertain relationship between those provisions and offshore oil and gas activities.
Giving governors of coastal states limited power over oil and gas activities is
consistent with our federal system of government and recognizes the joint interests
of the nation and coastal states in OCS development.

INTERIOR DEPARTMENT ADMINISTRATIVE POLICIES

Within the structure of the present leasing and development system, the Interior
Department could significantly increase the effectiveness of state'and local parti-
cipation by administrative actions.

RESOURCE REPORTS. The request for resource reports on the possible effects of
leasing on the environment or other conflicting uses of the OCS (e.g., shipping ane
fishing) is usually the first indication that the state has of the specific area
being considered for leasing. California received the resource report request for
Lease Sale #48 at least one month later than federal agencies. Copies of resource

138

reports, which are useful in responding to the subsequent call for nominations, are
,not generally made available to state and local governments. BLM should issue re-
source report requests to states at the same time they are issued to federal
agencies and promptly provide copies of all responses to the state and local
governments.

CALL FOR NOMINATIONS AND TRACT SELECTIONS. The Interior Department gave an
environmental briefing to state and locaT -representatives on areas being considered
for Lease Sale #48, but.the briefing was held after the deadline for responses to
the call for nominations had passed. When BLM-r-s-Pacific OCS Office briefed state
and local government representatives on tract recommendations being made to the
directors of BLM and USGS in Washington, the recommendations were discussed only in
a vague and general way, and no written copies of the recommendations were provided.
This prevented state and local governments from being able to respond to those
specific recommendations, which are-made on a tract-by-tract basis. In any case,
state and local government representatives were given insufficient time to prepare
for a tract selection meeting with Interior Department officials in Washington two
weeks later to discuss those recommendations.

The Interior Department should hold environmental briefings on areas under
consideration for 1ease before nominations are due. Responses to the call for
nominations from state and local governments and the public should be distributed.
State and local governments should be given written copies of the specific tract
.recommendations made by the area offices to Washington and allowed three weeks to
prepare comments on those recommendations.

ENVIRONMENTAL IMPACT STATEMENTS. In the past, state and local governments
have not been involved in the prepaFation of EISs, even though they should be involved
to ensure that their concerns are not neglected. BLM's efforts to involve state and
local governments in drafting the EIS for Lease Sale #48 are positive steps.
Public hearings on draft EISs, however, have been held so soon after the draft
became available that state and local governments lacked sufficient time to obtain
a copy, review it, and prepare.detailed comments. Public hearings should be held
no less than forty-five days, rather than thirty days, after the draft EIS becomes
available.

DEVELOPMENT PLANS. State and local representatives have not been invited to
informal discussions between USGS and offshore operators preceding formal submittal
of development plans, when state and local concerns might be accommodated more
easily than at a later time, after commitments have been made. State and local
representatives should be invited to participate in these meetings when the loca-
tion of facilities for producing, transportinq, storinq, or treating offshore oil
and gas are discussed.

ACCESS TO RESOURCE DATA

The California state and local governments are hampered in their efforts to
comment on proposed OCS leasing and development activities and to plan for onshore
OCS-related development by a lack of specific resource estimates, reserve estimates,
and production forecasts. This information is necessary for state and local govern-
ments to recommend appropriate lease stipulations, to recommend the deletion of
tracts from the lease sale with hazardous conditions that cannot be lessened or
avoided, and to respond to federal requests for comments on exploratory and develop-
ment plans and permits for drilling, platforms, pipelines, and other facilities.

139

Resource estimates, reserve estimates, and production forecasts are primary factors
in determining which means of producing, processing, and transporting oil and gas
are feasible. Onshore 2ffects, in turn, depend on the types and size of onshore
facilities required for processing and transport.

FEDERALLY CONTROLLED DATA. The federal government collects geophysical and
geologic data necessary to prepare resource estimates, reserve estimates, and pro-
duction forecasts through the Geologic Division and the Conservation Division of
the USGS.

GEOLOGIC DIVISION. The Geologic Division collects geophysical data and.bedrock
samples from rocT -outcroppinqs on the ocean floor, and, using these data, produces
general estimates of the resource potential of broad areas of the OCS.
These interpretive reports and the geophysical data and rock samples are available
to the general public in the open files of the Geologic Division.

CONSERVATION DIVISION. The Conservation Division contracts with private
exploration companies for the collection of these data and also buys information
offered for sale on the open market by the exploration companies. But these data
from exploration companies are supplied under strict conditions of confidentiality
that prevent their disclosure not merely to the general public, but to state
agencies as well. The Conservation Division also has access to information from
all geophysical and geologic surveys and receives well data from leased tracts.
Lessees are required to submit well logs, cores, core analyses, paleosamples, well
test results, and production information to the Conservation Division. 36/
California, the Gulf of Mexico, and the Gulf of Alaska are the only OCS areas where
exploratory and development drilling have taken place, and, therefore, presently
the only sources of well data.

DISCLOSURE OF DATA. Under revised regulations issued in 1976, raw geophvsi-
cal data will b@ -made Public ten years after the issuance of the exploratory permit.
The processed geophysical data, reprocessed geophysical data, and interpreted geo-
physical data will be released ten years after it is submitted to USGS. Nonetheless,
a public notice is issued immediate)y upon the identification of any hydrocarbon
deposits or environmental hazards discovered during geological exploration and con-
sidered sianificant by the Director of USGS. All other qeoloaic data, analyzed
geologic information. and interpreted geologic information will be made public ten
years after the permit is issued. All geologic data and information obtained from
deep stratigraphic drilling will be released five years after completion of the
well or 60 days after issuance of the first federal lease within 50 miles of the
well, whichever is earlier.
The new regulations al.so provide for the public release of data and information
collected after leases are issued. Geologic data and analyzed geologic information
will be made public with the lessee's consent while the lease remains in effect or
after two years, whichever is earlier. Interpreted geologic information, geophysical
data, analyzed geophysical information, and interpreted geophysical information will
be released to the public with the lessee's consent while the lease remains in
effect or after ten years, whichever is earlier.
Before these new regulations were established, Interior Department policy did
not allow disclosure of any of this information, which is considered proprietary.
These regulations became effective on June 23, 1976, and apply only to permits or
leases issued after that date. As a result, none of the post-lease geophysical or

140

geologic information held by the Conservation Oivision is currently available to
the state or local governments of California. -

HOLDING DATA CONFIDENTIAL. The Interior Department's qeneral policy of keepina
confidential all resource data and information obtained from exploration companies
or through submissions of lessees has been based on the general qrant of authority
to the Secretary in the OCS Lands Act to administer the federal OCS oil and cas
program. 87/ The OCS Lands Act is silent on whether these t1vpes of information
must be k-ept secret.
It is uncertain whether the Freedom of Information Act (FOIA) forbids the
disclosure of detailed resource data and information. Generally, the FOIA requires
federal agencies to make information available to the public. 88/ The Act does not
apply to matters that are "(3) specifically exempted from discT7oure by statute;
(4) trade secrets and commercial or financial information obtained from a person
and privileged or confidential; ...or (9) geoloqical and geophysical information
and data, including maps, concerning wells." 89/ Read literally, the statute does
not require this information to be kept secrJ_-- it simply exempts the information
from the provisions of the FOIA requiring that it be made available to the public.
The courts 'have differed, however, on whether information falling within exemptions
of the FOIA may be released or must be withheld from the public.
In Pennzoil Oil Co. v. Federal Power Commission, 90/ companies producing
natural gas offshore objecte@ to'an FPC order stating that detailed reserve informa-
tion and background data required of the producers by the FPC would be made public.
Thecompanies contended that the information consisted of trade secrets and
confidential geophysical information, publication of which would significantly
damage their financial interests. The producing companies claimed public disclosure
of this information is absolutely barred by exemptions four and nine of the FOIA.
The Fifth Circuit Court of Appeals held that "the mere fact that this information
is encompassed within the exclusions of the Freedom of Information Act does not
prohibit its disclosure." 91/ The Court said, "Interpreting the statute as an
absolute bar to the releas@_of certain information would be at war with the basic
principles embodied in the Freedom of Information Act." 99! Nevertheless, the
Court held that the Freedom of Information Act is not ii-relevant in determining
whether information encompassed in its exclusions should be disclosed and stated
that "where releasing the information serves no leqitimate function, this court
will prohibit disclosure." 93/ A balancing of the public and private interests
involved is required, the C6-u-rt said, to determine whether disclosure should be
allowed. 94/

Some courts have held the FOIA itself implies that parties submitting business
information to the federal government have a right to protection from having that
information disclosed, at least to competitors. 95,1 In another case, the Court
of Appeals for the District of Columbia Circuit Teld that "FOIA is neutral with
regard to exempt information; it neith.er authorizes or prohibits the disclosure of
such information." 96/

Parties seeking to prevent the d.isclosure of information have a rgued that the
FOIA must be interpreted in light of 18 U.S.C. �1905, a statute that makes it a
crime for a federal employee to disclose in any manner or to any extent not autho-
rized by law any information coming to him or her in the course of his or her
.employment or duties concerning or relating to trade secrets or to other confiden-
tial statistical data (among other things) of any person, firm, partnership,

corporation, or association. Since information of this nature would be exempt from
disclosure under exemptions four or three (which exempts matters "specifically
exempted from disclosure by srtatute") of the FOIA, its disclosure is not 'authorized
under the FOIA and its disclosure is prohibited under �1905. 97/ This argument
has been adopted by some courts '981 and rejected by others. '9-9/ The most complete
statement of this view can be foTnd in Westinghouse v. Schlesf-nger, 100/ which is
now on appeal to the U.S. Supreme Courf_.
The decision in Westinghouse, which relies heavily on the ruling of the Supreme
Court in FAA Administrator v. Robertson, 101/ has been questioned recently in Crown
Central P_(@f_ro 1 eum Corp. v. KK11 epp@e_., fCF2-/ F-Crown , Judge J ames R. Mi 11 er, J r - , states
his belief that the enactment of Pub-T-1c Law 94-409 effectively overrules FAA Admin-
istrator v. Robertson, and, consequently, the decision in Westinghouse to t e extent
that it held that �1905 is a statutory exemption applicable to the FOIA through
exemption three of that Act. *103/
To sum up, it is unclear whether the Interior Department could exercise discre-
tion and release detailed offshore resource data and information collected from
offshore operators pursuant to USGS regulations to the public. The circuit courts
of appeal are in disagreement; and an important case presenting similar issues,
Westinghouse v. Schlesinger, is on appeal to the Supreme Court. Some information
on offshore oil and gas resources and reserves is already published, however, by
the Interior Department.
FEDERAL REPORTS. The Interior Department makes estimates of OCS oil and gas
resources public in EISs and other Interior Department publications, using confiden-
tial information from the Conservation Division or information in the open files of
the Geologic Division or both. These estimates are flawed by the timing of their
release, their level of detail, and their inability to be compared.

Because the Interior Department publishes OCS estimates irregularly, only
when needed for an EIS or other publication, these analyses are not prepared or
revised on a systematic basis. The estimates do not incorporate new information
gathered during exploration and development, or even reflect such basic facts as
the failure to lease large areas covered in pre-lease sale estimates.

USGS and BLM do not publish estimates for individual tracts, units, or
structures. Instead, estimates are published covering multiple areas, even'though
more detailed estimates may have been prepared internally. Since published estimates
are aggregated, it is impossible for state and local analysts to correlate these
estimates with new information-pertaining to specific individual fields or tracts.

Estimates and forecasts prepared by the Interior Department are conflicting and
contradictory. Those for the southern California OCS aggregate different areas and
water depths, draw on differing resource data, and use varying methods and assump-
tions. Thus, useful comparisons cannot be made among various Interior Department
estimates or between Interior Department and industry estimates. Sometimes, estimates
given in different Interior Department publications will conflict directly. For
example, the Santa Barbara Channel EIS estimate of remaining recoverable resources
in unleased portions of the Channel is 40-150 MMB. At a BLM briefing
in December, 1976, seven months later,- an estimate of 40-900 MMB was
given.

142

The Interior Department, through USGS, should develop and publish an updated,
annual resource and reserve estimate and production forecast for all leased areas.
For areas without discoveries, resource estimates-should be provided by structure,
identifying the leases affected. For leases with credited discoveries, reserve
estimates and production forecasts should be provided by field. These reports
should specify the data, information, and assumptions used in making the estimates.
Immediatel'y after a-lease sale, the Interior Department should publish the tract-by-
tract resource estimates used in evaluating bids so that pre-lease sale resource
estimates can be revised to reflect the tracts actually leased.

STATE ACCESS. Most of the information needs of the California state and local.
governments will be met if the recommendations above are adopted. But, the
estimated amounts of recoverable oil and gas may become central to important policy
issues, as in the present controversy over the means of transporting oil from Exxon,s
Santa Ynez Unit in the Santa Barbara Channel.

Without geologic and geophysical data and information, which is held by both
the oil industry and -the Interior Department, the State must accept industry and/or
Interior Department interpretations since it is unable to make its own independent
analysis. This analysis is necessary in view of the variability of interpretations.
Exxon states that it has from 400 to 500 MMB of recoverable oil in the
Santa Ynez Unit, for example, while USGS estimates from 730 to 1100 MMB.
This is critical in a controversy of this nature, because Exxon maintains there is
insufficient oil in the Santa Ynez Unit to justify building the pipeline favored
by state and local government officials for the prevention of oil spills and
protection of air quality.

The California Division of Oil and Gas and the California State Lands Divi-
sion have the expertise to analyze and interpret geologic and geophysical data and
information in a confidential manner, as they have for state tidelands leases. At
present, however, they do not have the manpower or the funding necessary to under-
take large-scale analysis of OCS data and information.

Analysis of geologic and geophysical data is expensive, and duplication of
Interior Department analyses of OCS data would be wasteful in most cases. However,
in those instances where conflicting resource estimates or the Interior Department's
failure to develop necessary analyses in a timely fashion justify state expenditures
for such analyses, the Division of Oil and Gas or the State Lands Division should
perform such analyses.

When they do occur, the Governor should request either the State Lands Divi-
sion or the Division of Oil and Gas to prepare- the necessary reserve or resource
estimates. The Interior Department should permit that designated agency access to
geologic, geophysi@cal, and well data and information held by the Department under
strict conditions of confidentiality. These conditions must permit the state to
.use estimates based on this data and other information (i.e., oil characteristics,
production forecasts, and other factors that affect development, processing, and
transportation options) in public forums or documents, in the same manner that
estimates based on confidential data held by the USGS are sometimes used in reports
or briefings. Otherwise, the use of this information would be precluded in the
debate of important OCS issues,.and the state and local governments would
continue at a disadvantage in debates with the oi-1 industry and the federal
government.

143

For future lease sales, the Interior Department should go further than the
revised regulations for the release of resource data. 104/ The Secretary of the
Interior should require that coastal states have access--To geologic, geophysical,
and well data developed by lessees and geologic and geophystcal data collected under
permits on unleased tracts. Like information from operations on existin I leases,
these data should be subject to strict conditions of confidentiality while esti-
mates by state agencies based on these data should be allowed to be used in public
documents or forums.

The oil industry and contractors who work for them are greatly concerned
about the handling of resource data and inf 'ormation because geologic and geo-
physical data and information are valuable and marketable commodities. This
information is valued primarily for the competitive advantage it affords when
nearby tracts are offered in future lease sales and for negotiating ag ; reements
to share costs of pipelines and processing facilities. Providing California
State agencies access to resource data as recommended here should not, however,
significantly increase the risks of the disclosure of proprietary data to a
company's competitors. Both the California State Lands Division and the
California Division of Oil and Gas have proven they can handle proprietary data
in a confidential manner. There is no recommendation here to release geophysical
or geologic data to the public, but only to permit the State Lands Division or
the Division of Oil and Gas access to the data. These state agencies would
review only a small portion of the data collected offshore -- that data relevant
to a dispute over a particular development proposal, such as Exxon's proposed
offshore storage and treatment facility for the Santa Ynez Unit. In any case,
providing California or other coastal states access to resource data from leases
sold in the future should not cause a competitive hardship upon lessees, since
bidders with advance notice of this requirement could discount their bids to
reflect any loss of competitive advantage they might have anticipated from their
exclusive possession of information relevant to subsequent sales.
It should be noted that some of the oil companies* (Exxon, Chevron,
Mobil, Arco, and Phillips) operating off California have been cooperative in
supplying state agencies with information on their offshore reserves and esti-
mated resources. In contrast, Texaco refused to supply any information on their
operations off California to the OCS Project Staff writing this report.

STATE REVIEW OF DEVELOPMENT PLANS

Coas*tal states will receive information on development plans under new regu-
lations that allow governors to review and comment on development plans before USGS
approval can be given. 105/ But this, too, falls short of the need of state and
local governments. The period allowed for review and comment is so short (sixty
days) that it will be very difficult to analyze the submitted material and produce
,meaningful comments to USGS within the allotted time. The information submitted
to the states is also incomplete. Geologic and geophysical information and well
data and maps are withheld, preventing the states from making an independent assess-
ment of the resource potential and possible hazards. The federal government re-
quires this information in order to make its own independent analysis, but states
are left to rely on the judgment and assurances of the operators and USGS. As
noted above, the willingness of offshore operators to cooperate informally in
providing information about proposed development varies widely. Production sched-
ules are essential in estimating the size of onshore facilities and in planning
for the level of OCS-related impacts over time, but there is no requirement for
operators to supply production forecasts to the states.

144

The draft of OCS Order 15, putting into effect the new regulations providing
for state review of development plans, raises additional problems. I-06/ The
draft requires only general information on a county-by-county basis 6-n the size
and number of offshore operations and onshore facilities. This general informa-
tion is insufficient for planning purposes in California, where the five southern
coastal counties have over 400 miles of coastline. Operators are required to
assess acreage and the general location of new facilities to be constructed, but
in areas like California where oil and gas processing plants, Pipelines, refineries,
and terminals already exist, states need information about plans to use exist-
ing or expanded facilities. Information is required on the transportation of oil
and gas to shore, but the disposition of oil onshore after initial processing,is
also important; this has been the major issue in the Exxon/Santa Ynez controversy.
Estimates of persons engaged in onshore support activities are not disaggregated
to identify direct and indirect employment for each component of onshore and
offshore activities, preventing the states from making independent evaluations of
these estimates or anticipating the effects of changes in the operator's plans.

USGS should require operators to provide site-specific plans or options for
offshore operations and onshore facilities, plans to utilize existing or expanded
facilities as well as new facilities, plans to transport oil after processing,
and detailed estimates of the economic effects of planned offshore oil and gas
development. The period for state review of development plans should be
lengthened to 120 days, to begin upon receipt of the development plan by the
state and to run concurrently with USGS review.

FEDERAL COORDINATION

Within the Interior Department, OCS activities are coordinated through the
Office of OCS Program Coordination under the Assistant Secretary for Program De-
velopment and Budget. Secretarial Order 0274 states, in detail, how BLM, USGS,
and the Fish and Wildlife Service will interact on OCS-related activities. There
is no established procedure, however, for agencies outside the Interior Department
to participate in the OCS policy-making process beyond responding to the request
for resource reports early in the leasing process and acting on any permits over
which they have jurisdiction. For example, such agencies as EPA or the National
Maritime Service in NOAA have no real' opportunity to contribute to reviews of
exploration and development plans. Some procedure within the federal government
should be established to enable agencies with expertise in marine resource issues
outside of the Interior Department to contribute more to leasing and development
decisions.

STATE COORDINATION

OCS policy-making and regulatory functions in California are spread among
several state offices, boards, commissions, and departments; and there is no
systematic coordination of their activities. Local governments, federal officials,
and the industry sometimes are,forced to contact a number of state agencies to
obtain or convey information on OCS-related proposals or actions. State officials
involved in OCS issues keep in touch on an informal basis,,and the OCS Project in
the Governor's Office of Planning and Research has performed some coordinating
functions; but the focus of the state's OCS activities should be in the line state
agency responsible for coastal issues, the California Coastal Commission.

145

The Coastal Commission should take primary responsibility for: (1) coordinating
state and local government responses to proposed federal government and industry
actions; (2) disseminating information among state agencies and providing local
jurisdictions with technical assistance to participate in OCS leasing and develop-
ment decisions and to anticipate that development in local coastal plans; (3) assist-
ing state, regional, and local government agencies to identify and obtain federal
funds to support OCS-related projects and programs; and, (4) maintaining communica-
tion and exchanging information with other states on OCS-related matters. Additional
funds and staff positions should be allotted to the Coastal Commission-to carry out
these responsibilities.

E N V I R 0 N M E N T A L B A S E L I N E S T U D I E S P R-0 G R A M

A major concern of California state agencies and local governments is the
quality of environmental resource information upon which OCS leasing and development
decisions are based. The Bureau of Land Management's major effort to acquire such
information is made through its Environmental Baseline Studies Program. The Bureau
instituted this program in 1973 to fulfill its obligation under the National Environ-
mental Policy Act "to utilize a systematic, interdisciplinary approach that would
.ensure the integrated use of the natural and social sciences in any planning and
decisionmaking which may have a significant impact on the human environment." 107/

Baseline studies have been undertaken in every frontier area off the U.S. coast
where Outer Continental Shelf leasing and development is taking place or lease sales
are planned. As described by BLM, the objectives of the Baseline Studies Program
are to:

1. provide information about the OCS environment that will enable the
Department and the Bureau to make sound management decisions regarding
the development of mineral,resources on the federal OCS;

2. answer questions concerning the impact of oil and gas exploration and
development on the marine environment;

3. establish a basis for prediction of the impact of OCS oil and gas
activities on frontier areas; and,

4. provide data that will.result in modification of leasing regulations,
operating regulations, or OCS operating orders to permit more efficient
resource recovery with maximum environmental protection. 108/

The Baseline Studies Program consists of seven major study elements:

1. Historical Data Summaries;

2. Conferences;

3. Reconnaissance Studies;

4. Benchmark Studies;

5. Fates and Effects Studies;

146

6. Modeling; and,

7. Site Specific Monitoring. log/

Historical Data Summaries summarize existing information and
update the current status of the data base for biology, chemistry, geoloqy,
and toxicology. In addition to identifying available information for use in the
environmental impact statement on a lease sale, a central purpose of this element
is to identify data and information gaps and future research needs.

Conferences are held to provide BLM with guidance on structuring and integrating
baseline studies. The Bureau forms committees: to examine particular subject areas
or research problems such as persistence of hydrocarbons in-the marine environment.
The Southern California Baseline Studies Program was initiated at a conference held
on December 5-7, 1974, where representatives of state, federal, and local government;
industry; and the academic community presented recommendations on structuring
research and establishing priorities for the studies. 110/

Reconnaissance Studies consist both of-broad area characterizations and site
specific investigations designed to yield qualitative information on areas of
particular interest or concern.

Benchmark Studies are long range studies conducted over many years to establish
the range of variation in biological, physical, geologic, and chemical features of
a lease area. The Studies provide information that will enable the Bureau to
identify particularly sensitive environments that should not be opened to oil'and. -
gas or other mineral development.

Fates and Effects Studies provide information on transport, dispersal, biological,
chemical, and physical alteration and ultimate fate of contaminants introduced to
the marine environment by' OCS development. The effects of these contaminants on the
environment are also investigated.

Modeling efforts use information and data produced by other elements of
the Baseline.Studies Program to predict spill frequencies, pollutant trajectories,
'wave energy,.and environmental impacts.

Site Specific Monitoring is conducted at a small site under development in order
to determine the type, magnitude, and effects of contaminants introduced into the
marine environment by drilling rigs and OCS activities.

While pirogram designs vary from region to region, Baseline Studies are
generally conducted in four phases. Phase I surveys the existing environmental.
knowledge concerning a proposed leasing area; Phase II is the actual baseline
survey and data collection to establish a benchmark for future comparisons with
past oil and gas development conditions. Phase III is.programmed to accomplish
specialized research that fills data.and information gaps identified-in Phases I
and II. Finally, Phase IV is the long range monitoring of a leased area and is
designed to detect changes over time in environmental conditions that.result from
oil and gas exploration and development. Ill/

Progress to date in southern Ca.lifornia includes completion of Phase I and the
publication of A Summary of Knowledge of the.'Southern California Coastal Zone and,
Offshore Areas prepared by the Southern California Ocean Studies Consortium. 112/.

11-76658 147

The first year of Phase II, a benchmark sampling program of intertidal, benthic,
and water column stations, has also been completed. 113/ In addition, the first year
census study of marine b-irds and mammals by the Bureau of Land Management was
released in April 1977. 114 / This effort is particularly significant in that survey
activities conducted while Lease Sale #35 was in progress identified critical bird
and pinniped habitats in the northern Santa Barbara Channel. Identification of
these sensitive resources resulted in deletion of 29 partial or whole tracts south
of San Migu,el and Santa Rosa Islands and five tracts off Santa Barbara Island. 115/

Phase II studies in the Lease Sale #35 areas also resulted in the inclusion
of special stipulations in leases for the Tanner-Cortes Bank area. The stipulations
require lease operators to conduct special biological surveys before they begin
any drilling. They also prohibit.dumpinq of drill cuttings and drilling muds on
the drill site. 116/

In fiscal year 1975, the Bureau of Land Management awarded four contracts
for conduct of the Southern California Environmental Baseline Studies Program
totaling $4,629,260, as follows: 117/

Contractor Purpose Cost Date of Award

Southern Organize and administer $ 18,996 11/15/74
California conference/workshop "Recommen-
Academy of dations for Baseline Research
Sciences in Southern California Relative
to Offshore Development"

Regents of the Bird, Pinniped, and Mammal Study $ 652,000 3/28/75
University of
California

National Aero- Supply film and processing in $ 28,000 5/l/75
nautics and support of bird and mammal
Space Admin- study
istration (Ames
Research Center)

Science Appli- Environmental baseline data $3,930,264 6/30/75
cations, Inc. collection, storage and analysis

Fiscal year 1976 contracts involve continuation of work begun in 1975.

Baseline studies conducted during Lease Sale #35 made some contribution to the
tract selection process. Nevertheless, both the Southern California and the National
Baseline Studies Program have been subject to severe criticism. One forum for the
expression of concerns over the program has been the National OCS Advisory Board
and its Outer Continental Shelf Environmental Studies Advisory Committee. These
bodies were organized in late 1975 to advise the Secretary on OCS leasing and develop-
ment management policy. 118/
The principle objection to the program has been that studies have not begun
well enough in advance of lease sales to enable full and complete assessment of pro-
posed lease areas before leases are offered for sale. Critics also feel that
research and data collection are not focused sufficiently to provide detailed infor-
matton required to project adverse effects and plan to correct them. The

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program is designed to identify the adverse consequences of oil and gas drilling
and production activities after areas are already committed to development. 119,/
Recommendations for improving the Program include increasing coordination of
research and exchange of information among federal agencies and state governments
and structuring and administering the Program in closer coordination with the OCS
leasing program so that information from the studies provides timely and pertinent
information for pre-lease sale decisionmaking.
Early in 1976,the OCS Advisory Board urged the Department to incorporate
nearshore and onshore studies in the Baseline Studies Program. In response to
this recommendation the Bureau of Land Management, in cooperation with t 'he Depart-
ment of Commerce's Office of Coastal Zone Management, initiated a study of state
information needs for OCS planning activities. The results of this effort were
published in May 1977, and the Department has taken steps to implement recommen-
dations made in the report. 14"Q/

While some improvements in the Environmental Studies Program have been made
over the last year, momentum behind this effort has increased under new leadership
in the Department of the Interior. In addition to the Department's internal
evaluation and restructuring of the manner in which environmental baseline studies
are designed and administered, the National Academy of Sciences is expected to
publish a detailed critique of the Program in late 1977. 121/

Finally, postponement of,Lease Sale #48 from March, 1978, to at least early 1979
automatically increases the amount of environmental baseline studies data and informa-
tion that will be available for incorporation in the Environmental Impact Statement
and for making tract evaluation and selections. It is now incumbent upon state and
local governments to make their data and information needs known and to participate
to the greatest extent possible in restructuring the environmental baseline
studies program.

STATE AND LOCAL CONTROLS

Production and processing of federal OCS oil and gas generally requires that
state and local governments review and approve some part of the operation. Typically,
in California, the facilities falling within this category include pipelines to
shore (within the state's three-mile jurisdictional limit), processing and storage
facilit.ies, and marine terminals with oil storaqe tanks and one or more additional
pipelines across state-owned tidelands.

Onshore facilities are not, however, always required. Some North Sea opera-
tions store and process oil offshore on fixed or floating processing, storage, and
transfer facilities which could serve the Santa Ynez Unit within federal waters, thereby
avoiding the jurisdiction of the Coastal Commission and its permit conditions. Where
onshore facilities are involved, however, state and local governments have some means
available to review and establish conditions for their location and operation.

L 0 C A L P L A N N I N G A N D Z 0 N I N G

Cities and counties in California have the primary authori ty for planning and
controlling land uses within their jurisdiction. State law requires every city and
county to adopt a plan consisting of a statement of development policies accompanied

149

by maps and a text describing objectives, principles, and standards.1-22/ Each plan
must address nine major problem areas: land uses, traffic circulatio@_,housing,
conservation, open space, seismic safety, noise, scenic highways, and safety. But
the treatment of these problems and other issues addressed in the plan is generally
left to local determination. State law merely establishes the basic procedural
requirements which must be observed before the local legislative body adopts or
amends a plan. These include public notice, public hearing, and a planning
commission report.
Zoning ordinances regulating the use of land and buildings are the basic tools
for implementing a general plan. These ordinances are valid only to the extent
they are consistent with the general plan and, like the plan, they may be adopted
or amended by the local legislative body only after hearings and a report from the
local planning commission. Zoning ordinances usually take the form of rules speci-
fying the uses which will be permitted in zones identified in the general plan.
Each type of zone usually recognizes uses that are permitted as a matter of right
and others which may be allowed only with a conditional use permit issued by the
local legislative body following a review of the particular design and operational
features of the proposed facility.

Zoning ordinances, then, are the reference point for land use decisions. If
oil-related facilities are allowed as a matter of right, no further discretionary
decisions are left to local authorities, If, however, oil-related development is
prohibited or allowed only on a conditional basis, public agencies retain some
discretion for regulating the design and operation of proposed facilities. Where
a development is inconsistent with the general plan, the developer must obtain
local legislative approval in a two-step process before the facility can be sited.
First, the general plan must be amended following state requirements for public
notice and hearing; then the zoning ordinance must be amended following a similar
procedure of public notice and hearings. Where a propOSL: facility is consistent
with the general plan, but because of its nature or location is not allowed as a
-matter of right, the developer must obtain local legislative approval'in a one-step
process. This decision is usually framed in one of two ways: as a rezoning to allow
uses previously prohibited by the ordinance;' or as approval of a conditional use
permit subject to conditions affecting the design and operation of the facility to
assure compatibility with existing uses. Rezoning and conditional use permits create
similar hurdles for developers. Both are discretionary decisions by the local
legislative body and may be made only after compliance with state procedural require-
ments including a planning commission hearing and recommendations and compliance with
the EIR requirements of CEQA. It is, of course, possible that this could also become
a two-step approval if a zoning change was required and the facility was of a type
requiring a conditional use permit, regardless of zoning.

SANTA BARBARA REGULATIONS

The content of zoning ordinances varies from jurisdiction to jurisdiction.
Santa Barbara has always been concerned about oil development and therefore offers
a good model to study. Oil and gas facilities are allowed in Santa Barbara only after
a detailed case-by-case review by the Planning Commission and County Board of Super-
visors. The County zoning ordinance allows processing facilities in three types of
districts: General Agricultural, "0" Zone Overlays, and Planned Manufacturing (PM).
The ordinance alone would allow facilities in some cases without conditional use
permits or other case-by-case review, but a 1967 policy resolution by the Board of
Supervisors is quite restrictive. The resolution requires VM" zoning for all oil
and gas processing facilities.

150

11PM11 zoning imposes very tight control over the design of proposed uses. Since
the PM designation must be applied for by the land owner, the resolution, in effect,
mandates a rezoning for every processing plant. The rezoning request must be
accompanied by a development plan which is submitted to the Board of Supervisors
for approval. In addition, before any building permits are issued, the developer
must submit to the Planning Commission a "precise plan" which incorporates design
and operational controls required by the Commission and the Board of Supervisors.
The procedure affords the County a great deal of discretion and control when
approving oil-related facilities.

In Santa Barbara, the first step in obtaining a conditional use permit or
rezoning is to apply to the Planning Department. The Department's initial review
determines whether the applicant has requested the proper action (rezoning, new
or amended conditional use permit, etc.) or whether the request should be recharac-
terized., thus changing the steps ultimately required for approval. Once an applica-
tion is accepted, it is reviewed concurrently by the County Office of Environmental
Quality in order to begin'environmental impact assessment and by a committee of
agencies (parks, public works, planning, petroleum' administrator, APCD, etc.) to
assess its conformity with other county policies. The Planning Department staff
uses both these reviews in preparing a report to the Planning Commission. The
Planning Commission then acts on the plan change, rezoning, or permit as appropriate,
and sends the matter to the Board of Supervisors for final action.

The issues raised in Santa Barbara for resolution through permit conditions and
development plan approval generally deal with measures to ameliorate adverse effects
at the site: air and noise emission and water discharge limits; grading, excavation
road building, landscaping, and screening conditions; and, environmental monitoring.
The rezoning ordinance for the Las Flores Canyon processing facility, for example,
incorporated seventy-three conditions covering the above areas and including
assumption by the operator of liability without fault for offsite damage and for
the periodic testing of oil spill containment and cleanup equipment at the County's
request on an unscheduled basis. The County began environmental impact analyses
early in the application process to provide the specific information needed for
permit and rezoning conditions to mitigate adverse results without unduly delaying
an application while these factors were reviewed.

C 0 A S T A L A C T

The Coastal Act of 1976 (SB 1277) sets forth statewide policies for conserving
and developing the coastal zone and requires that between 1978 and 1980 each local
government within the coastal zone bring its general plan and zoning ordinances into
conformity with the statewide coastal policies. 123/ The,Act establishes policies
on public access, recreation, development, and protection of marine and land re-
sources in the coastal zone. While these subjects must be addressed in the general
plan, the Coastal Act specifies the content of the policies which coastal jurisdic-
tions must implement through their general plans.

The Coastal Act requires a permit for any development within the coastal zone.
In the initial states of implementing the Act, these permits will be granted by the
State Coastal Commission. After local governments develop Local Coastal Plans
(LCPs) and the state commission certifies them as adequate, the permit authority
will be delegated to.local governments. The state commission will continue to
assure that LCPs are consistent with Coastal Act policies and to review and approve
LCP amendments before they take effect.

151

State coastal development permits must be obtained in addition to any other
permits required by state or local law. Thus, until LCPs are certified, the Coastal
Act adds another permit requirement. Once a local government obtains approval of its
LCP, however, the coastal permit should create no delay beyond that currently found
in local land-use decisions, because local governments can choose to proceed
concurrently on conditional use and coastal development permits, or to rely
exclusively on conditional use permits, so long as they incorporate the substance
of statewide coastal policy.

Even with an approved LCP, the devolution of permit authority to local
government is not absolute. Local decisions concerning any "major energy facility"
or involving a conditional use permit may be appealed to the State Commission.
This means, in practice, that virtually all permit decisions for OCS-related on-
shore development will be subject to appeal. The Coastal Act anticipates that in
some cases the State's role may be even more intrusive than merely to decide permit
appeals. Where an LCP is unduly restrictive, the State Commission may step in and
amend it to facilitate energy siting upon a finding:

that a public need of an area greater than that included within
the certified local coastal program would be met, that there is
no feasible, less environmentally damaging way to meet such need,
and that the proposed amendment is within the policies of (the
Act) . 124

Depending on the circumstances, any of the general Coastal Act policies
regarding beach access and protection of the land and marine environment may apply
to a proposed OCS-related development. There are five policies, however, explicitly
aimed at shaping OCS-related development. Section 30232 calls for "protection
against the spillage of crude oil, gas (and) petroleum products" and "effective
containment and cleanup facilities and procedures" for spills that do occur. Sec-
tion 30250 expresses a preference for new industrial development "within, contiguous
with, or in close proximity to" existing developed areas. Section 30260 recignizes
the need for accommodating "coastal dependent facilities" and provides that they
"shall be encouraged to locate or expand within existing sites and shall be permitted
reasonable long-term growth." Two additional sections express opposition to the
proliferation of single-company, single-purpose facilities along the coast. Section
30261 calls for "multicompany use of existing and new tanker facilities ... to the
maximum extent feasible and legally permissible." Section 30262 provides for the
accommodation of oil and gas development when "new or expanded facilities" are
11consolidated to the maximum extent feasible and legally permissible" in order to
reduce the number of wells, support facilities and sites necessary for economic
production.

It is not yet possible to determine the effect of these policies. They will
undoubtedly be elaborated on a case-by-case basis as they are applied by local
governments and the State Commission to establish permit conditions for particular
development proposals. One apparent-problem with the case-by@-case approach is that
some of the policies, such as consolidation, cannot be carried out in a vacuum by
one local government. The configuration of leases from previous sales in the Santa
Barbara Channel and from Lease Sale #35 suggests two potential areas for cross-
jurisdictional cooperation. In the eastern end of the Santa Barbara Channel,
operators from several units have indicated the technical feasibility of landing
and processing crude in either Santa Barbara or Ventura Counties, suggesting the
desirability of cooperative planning to encourage consolidation without necessitating

152

the intervention of the State Commission for that purpose. Similarly, production
from the leases in San Pedro Bay can be feasibly landed in either Los Angeles or
Orange County. Cooperative planning will be necessary to implement Coastal'Act
policies with regard to this development.

A I R Q U A L I T Y P E R M I T S

In addition to other required state and lo'cal development approvals, onshore
processing, storage, and transportation facilities with any air emissi'ons may also
require one or more air-related permits. These are discussed in Part Four,
Chapter III.

BRIDGING THE GAP: CZMA

The CZMA was enacted in 1972 to encourage states to develop comprehensive
Coastal Zone Management Programs. 125/ That Act provides federal financial assistance
to states for the purpose of devel'oping both coastal zone planning and management
programs. In addition to federal financial assistance, one of the incentives for
state participation was the promise of a new federal-state partnership through-
which federal programs and decisions affecting the coastal zone would be coordinated
and made consistent with the state's program when it matured from the planning into
the implementation phase. California is now at the crossroads between planning and
implementation. The development of the California Coastal Plan and the work
currently being undertaken by the Coastal Commission pursuant to the recent Coastal
Act (SB 1277) have been supported by planning grants under Section 305 of the CZMA.
Passage of the Coastal Act should qualify California for management grants under
Section 306 of the CZMA as soon as the federal office of Coastal Zone Management
approves the state's management program. That approval will trigger application of
the Act's so-called "consistency provisions" to federal programs, activities,
licenses, permits, and grants within or affecting California's coastal zone.

The CZMA requires fe 'deral programs and activities to be consistent with states'
coastal programs and sets out procedures for determining whether they are or not.
The Act creates a mechanism to review both the lease sale and subsequent permits
for consistency with the state plan. Section 307(c)(1) of the Act provides:

Each Federal agency conducting or supporting activities directly
affecting the coastal zone shall conduct or support those activities
in a manner which is, to the maximum extent practicable, consistent
with approved state management programs.

This brings the initial federal decisions regarding timing, size, location, and
conditions of a lease sale within the.co'nsistency provisions of the Act. In addi-
tion, the CZMA has always contemplated that individual,decisions, below the general
program level, would also be tested for consistency. The 1972 Act contained general
language requiring a certification of consistency by "any applicant for a required
federal license or permit to conduct an activity affecting 1-and or water uses in the
coastal zone...." 126/ This language wou'ld have probably applied to OCS operators,
but it has been superseded by Section 307(c)(3)(B) in the 1976 CZMA Amendments which
addresses OCS operating permits directly and requires that OCS exploration and
development plans be consistent with the states' coastal program.

153

C 0 N S I S T E N C Y FOR LEASE SAIES

At first blush, the general consistency requirement for "federal activities"
(Section 307(c)(I)) seems to provide a major new tool for California to review and
shape all or part of an adjacent offshore leasing program. Issues that might be
appropriate for resolution at this stage include the deletion of particular tracts
or areas because their development is incompatible with state environmental concerns
or the inclusion of lease stipulations regarding pipeline corridors, schedules for
timing development, or location and operation of onshore facilities to promote con-
solidation or.otherwise assure compatability.with state policies. A detailed
analysis of the Act and its implementing regulations, however, points out major
procedural and substantive hurdles qualifying that conclusion.

LEGAL HURDLES

The substantive mandate of the CZMA is that each federal agency "conducting
or supporting activities.directly affecting" a state's coastal zone shall do so in
a manner "which is, to the maximum extent practicable, consistent with an approved
state implementation program" (emphasis added). In the case of a lease sale, the
first question is whether a sale alone is an activity which directly affects the
coastal zone. That subsequent activities like drilling, platform placement, and
transportation and processing -- which can occur only after a sale -- may affect
the coastal zone is patent; but it is not self-evident that the sale alone has a
direct effect. The second question whether the leasing program is consistent
"to the maximum extent practicable" becomes a real issue only if a court can
first be persuaded that a sale alone directly affects the state's coastal zone.

The Office of Coastal Zone Management (OCZM) has proposed a strict definition
of maximum practicable consistence to restrict the loopholes through which federal
agencies might attempt to squeeze past state requirements. 1?7/ The thrust of the
OCZM implementing regulations is unambiguous; it is to forcefully encourage federal
agencies, insofar as that can be justified within their basic mandate, to tailor
their activities so that the concerns of coastal states and local governments are
fully reflected. Between this noble intention and its successful execution, how-
ever, lies a legal, political and administrative briar patch.

SETTLING DISPUTES

When conflicts between federal and state programs arise and the affected
agencies can reach an agreement, there is no problem. Where such an amicable
resolution is not obtained, however, a key concern for the State of California and
local governments is whether they can enjoin an action, such as a lease sale, which
they have determined to be inconsistent with state policies.

The 1972 CZMA established no mechanism to enforce the consistency clause
regarding.federal activities or to appeal federal decisions made over state objec-
tions. It was presumably intended that where a compromise could not be negotiated,
the aggrieved state or local government would proceed directly to federal court
for judicial relief. In the 1976 CZMA Amendments, Congress cut off this easy access
to judicial review and brought consistency disputes within the mediation process
established for approving initial state plans. To implement this provision, the
OCZM has proposed an elaborate procedure which must be followed before going to
court..

154

OCZM's proposal includes a mandatory negotiation period, a formal administra-
tive hearing.' a "mediation conference" and proposed decision by the Secretary of
Commerce, a review of the decision by OMB, and finally, a determination by the
Secretary of Commerce whether the proposed federal action is consistent with the
.state program or not. 1281 The San Francisco Bay Conservation and Development
Commission (BCDC) estimates that at a minimum, the mediation process will take
eight months. 12J/ At the end of the process, even if a state prevails, there may
be no final resolution. The Secretary of Commerce has no authority to halt any
federal activity. Thus, if he finds that an activity is inconsistent with a state's
program, he merely reports that decision to the President for transmittal to
Congress. In the meantime, while the mediation is underway, the federal agency
may proceed with its program. Since state concurrence with a determination of
consistency is not a precondition to any federal activity, and the Secretary has no
direct authority over other federal agencies, a state may ultimately have to
proceed to court for an enforceable judgment if no settlement is reached.

The BCDC, reflecting its own position and that of Coastal Commission staff,
strongly objected to the "cumbersome, protracted process" proposed in the regula-
tions:

(They) will render the consistency provisions unuseable for all
but those agencies with large staffs and plenty of time to devote
to this kind of thing. Neither BCDC nor the Coastal Commission
has either the staff or the inclination to expend our very limited
resources in this fashion when the end result is at best a recom-
mendation to the President that he make a report to Congress ....
Mhese regulations permit federal agencies to bury disagreement
over consistency in a process that because of its length and
complexity almost guarantees a lack of federal accountability. 130/

Despite the complexity of the mediation process, the OCZM defends the basic
approach on two primary grounds. The first defense i 's that the CZMA amendments
require mediation and may encourage compromise settlements since, if a judicial
relief were available at the outset, "a federal agency extreme position" and "a
state extreme position" would be offered the court without the benefit of "the
findings, guidelines for review, proposed resolutions, and final determinations
developed by the Secretary who is charged with administering the National Coastal
Zone Management Program." 13,1/ The second response is that despite its complexity,
the process provides for consistency determinations in a neutral forum before the
Secretary of Commerce that will ultimately better serve state interests-than review
procedures established by interested federal agencies whose activities are being
challenged.

CONCLUSIONS

Final conclusions concerning the impact of the CZMA on the Department of
Interior OCS leasing program are still premature. The consistency provision does
not change the basic position of the state with regard to its ability to influence
the timing, size, location, and special lease conditions of an OCS lease sale.
Those decisions are s-till exclusively federal decisions. To challenge them in any
way, a state must carry the burden of demonstrating their inconsistency with
the coastal plan and pursuing the matter through a protracted mediation procedure
whose outcome is not binding even if the state prevails. The mediation process,
however, may provide a workable framework for resolving differences where there is
good faith among the parties. The key to that resolution lies not so much in
recourse to the provisions of the CZMA, as in the willingness of the Interior
Department to cooperate with a state when conflicts are identified.

155

C 0 N S I S T E N C Y FOR EXPLORATION AND
bEV ELOP MENT PLANS

The CZMA establishes two different procedures through which the consistency
of proposed developments can be checked against state coastal policies. OCS
operators have the choice of either procedure in seeking approval. Since Cali-
fornia's Coastal Program has not yet been approved by OCZM and thus the consistency
requirements are not yet in effect, there is no experience to indicate which of the
alternative routes will be invoked by operators seeking state certification that
their proposals are consistent with coastal policies.

The 1972 Act provided that federal "licenses and permits" for activities
affecting the coastal zone could be issued only following a determination that the
activity was consistent with an approved coastal program. 132/ Although there is no
explicit legislative history on the point, it is reasonable to infer that federal
approvals for exploration and development plans would have been covered by the
general term "license 's and permits." Other approvals, such as pipeline and plat-
form location permits from the U.S. Army Corps of Engineers, would clearly fall
within the consistency provisions. The 1976 amendments to the CZMA elimi.nated all
ambiguity about the inclusion of exploration and development plans within the con-
sistency provisions of the Act. Section 307(c)(3)(B) provides that any person
submitting an OCS exploration or development plan to the Secretary of Interior
shall:

attach to such plan a certification that each activity which
is described in detail in such plan complies with (the affected)
state's approved management program and will be carried out.
consistent with such program. No federal official or agency
shall grant such person any license or permit for any activity
described in detail in such plan until such state or its
designated agency receives a copy of such certification and
plan, together with any other necessary data and information
and until --
MOM(The state actually or presumptively concurs in
the certification or consistency), or
(iii) the Secretary finds ... that each activity which is
described in detail in such plan is consistent with
the objectives of this title or is otherwise necessary
in the interest of national security. (emphasis added)

Thus, an operator can proceed under the 1976 amendments to obtain a single
state review of his development based upon detailed descriptions of proposed
activities in the exploration and development plans, or he can seek approvals
piecemeal,under the 1972 procedure as various federal permits are required. In
either case, the state role is stronger than that provided with regard to "federal
activities" discussed above. Instead of putting the burden on the state to demon-
strate that a proposed action is inconsistent and to enforce such a determination,
the burden here is on the applicant to demonstrate that the action is consistent.
Further, unlike the case with federal activities where an activity may continue
pending the outcome of a consistency determination, the finding of consistency is
here a pre-condition to the issuance of a license or permit. The provisions,
however, by no means constitute a state veto of federally permitted activities.
In the case most likely to arise from OCS development, the Secretary of Commerce
may override a state's objection if it is found that "the activity is consistent

156

with the objective of this title...." The OCZM views this procedure as a
"variance" and has proposed regulations consistent with that view. 133/ -To over-
ride a state's objection, the Secretary must first find that the activity is con-
sistent with the broad purposes of the CZMA. This is an imprecise standard with
a great deal of discretion since the purposes include, among others, the conflicting
directives "to preserve,.protect, develop, and where possible, to restore or enhance
the resources of the Nation's coastal zone for this and succeeding generations...."
114/ The refinement proposed in OCZM regulations is a requirement that the Secre-
tary find, in addition, that the activity would "not have a significant negative
impact upon the integrity of the Management program" and that requiring consistency
would "impose an unreasonable burden upon the applicant." 135/

For disputes between a state and an applicant, the administrative procedure is
almost identical to that provided for disputes between a state and a federal agency
over the consistency of the agency's activity. The only difference is that appoint-
ment of a hearing officer is optional, and OMB is not consulted. The Secretary's
decision is final for purposes of judicial review.

The interaction of the general 1972 p rovision for "licenses and permits" and
the 1976 amendment for exploration and development plans may vary from case to
case. The 1976 provision exempts each activity "described in detail" in an approved
exploration or development plan 'from any further consistency review. This allows
OCS operators the option of seeking a one-stop consistency review for all the
federally permitted aspects of their operations or of presenting each successive
phase of the development piecemeal for review as a new federal permit is required.

Interior Department regulations concerning exploration and development plans
pave the way for piecemeal review by narrowly circumscribing the scope of those
documents to exclude production schedules, transportation plans, and onshore develop-
ment. Exploration and development plans are defined to include:

1) description of the drilling vessel or platform;
2) general location of each well;
3) structural interpretations based upon available data; and,
4) other data prescribed by the USGS Area Supervisor. 136/

OCS order #15 does require lessees to provide the state with information concerning
onshore facilities and operations expected to accompany proposed development. This
information is purely advisory, however, since Interior Department regulations define
"development plan" 13*7/ so narrowly that associated facilities are excluded from
consistency review.

Because of the narrowness of the issues that must be offered for state review
in-exploration and development planning, the 1976 CZMA amandments have provided
little substantive change in the state's role from that previously established
through license and permit review under the Act. The primary difference seems to
be that the Act now affords a lease operator the opportunity to seek a comprehensive
consistency review for all required federal permits at an early stage, if he so
desires. Operators, however, need not seek an early review and may proceed seriatim
seeking an'additional certification of consistency at each step where a federal
permit is required.

157

From an operator's perspective, there are some difficulties with an early
mandatory review. Planning is a process of discarding old proposals and generat-
ing new ones as exploratory work provides increasingly more reliable information
upon which the economics of various alternative development patterns can be
assessed. In this climate of uncertainty, operators often see little benefit
-from early discussion which tends to commit them to any particular proposal for
development. The problem, from a public planner's perspective, is that the lack
of an early mandatory review forces piecemeal consideration of devel@opment without
an opportunity to assess cumulative effects or to gauge the realistic range within
which plans are uncertain or may be modified. The CZMA amendments of 1976 offer
the operator a chance to seek one early review by the state. But that review may
come too early in the development process to allow him to provide sufficient detail
on proposed activities so that the state could approve the proposal and waive
further opportunities to comment and assess the consistency of the development
with coastal policies.

CONCLUSION

CZMA provisions allowing the state to certify the consistency of development
plans and federal permits, despite their inherent limitations, should nevertheless
provide a significant new tool for reviewing offshore proposals. The potential
can be seen by looking back at what might have happened had the procedure been
available when the Interior Department'approved Exxon's floating plans for a
storage and terminal facility just outside state waters on the Santa Ynez Unit.
The ground for the decision was that California failed to offer a permit under
'"reasonable" terms after Exxon's "good faith effort" to obtain one. That deter-
mination by the Secretary of Interior was made without any formal proceeding which
allowed the state to present its case on the necessity or reasonableness of the
permit conditions offered. Implementation of the consistency provisions of the
CZMA should provide both a process and the substantive grounds for resolving dis-
putes of this type to better reflect the state's coastal management objectives.

158

FOOTNOTES

1. U.S.C. 1331 et seq.
2. Don Kash, et al., Energy Under t he Oceans (Norman, Oklahoma: University of
Oklahoma Press, 197@T. pp. V-Z8.

3. Congressional Research Service, Effects of Offshore Oil and Natural Gas
Development on the Coastal Zone (Washington, D.C.: Government Printing Office, 1976),
pp. 68-70; Department of the Interior, Leasing and Manadement of Energy Resources on
the Outer'Cohtih0ht6l Shelf (Washington, D.C.: GPO, 1976), pp. 13-14.

4. Department of the Interior, 92_. cit., pp. 14-15.
5. 30 C.F.R., Federal Register, 40 (June 23, 1976)9 pp. 25893-25897.

6. M. V. Adams, et al., Mineral Resource Management of the Outer Continental
Shelf (Washington, [email protected] _GPO9 1975), Geological Survey Circular 720, pp. 7-8.

7. Committee on Appropriations, U.S. House of Representatives, Hearings on
Department of the Interior and Related Agencies Appropriations for 1977, Part 4
(Washington, D.C.: GPO, 1976), pp. 131-33.

8. General Accounting Office, Outlook for Federal Goals to Accelerate Leasin_q
of Oil and Gas Resources on the Outer Continental Shelf (Washington, D.C.: GPO,
March 19, 1975)9 pp. 8-10.

9. 42 U.S.C. 4321 et seq.

10. Federal Register, 40 (October 1, 1976), p. 45171.

11. 43 C.F.R. Part 3300.

12. 43 C.F.R. Part 3304.1.

13. 43 U.S.C. 1337(b)(3); 67 Stat. 464, 8(b)(3).

14. 43 U.S.C. 1334(a)(1); 67 Stat; 464, 5(a)(1).

15. Ibid.

16. Union Oil v. Morton (9th Cir., 1975), 512 F.2d 743, 749, citing Gulf Oil
T -- 9-493 F.2d 141.
v. Morton 9th Cir., 1973T

17. 30 C.F.R. Parts 250.2(j), 25r.11.

18. 30 C.F.R. Part 250.11.

19. 5 U.S.C. 551 et seq-

20. 30 C.F.R. Part 250.31.

21. 30 C.F.R. Part 250.34(a).

159

22. 42 U.S.C. 433s(c); 83 Stat. 852, 102(2)(c).

23. 40 C.F.R. Part 1500.6.

24. 30 C.F.R. Parts 250.34 '250.41, 240.91; Kash et al., cit., P. 44; Irvin
M. Waitsman, Summary of Federal Responsibilities in Oi7a-nd Gas Le-as-'l'-ng on the
Outer Continental Shelf (Boston: New Enqland River Basins Commission, December,
1974), p. 7.

25. 43 U.S.C. 1333(f); 67 Stat. 463, 4(f).

26. 33 U.S.C. 1343, 40 C.F.R. Part 125.

27. Memorandum of G. William Frick, General Counsel, to Rebecca W. Hanmer,
Director of Federal Activities, dated September 23, 1976.

28. 43 U.S.C. 1333(e)(1).

29. Pacific OCS Order No. 4.

30. 30 C.F.R. Part 250.44.

31. Pacific OCS Order No. 3.

32. 30 C.F.R. Part 250.34(b).

33. Department of the Interior, U.S. Geological Survey, Final Environmental
Statement, Proposed Plan of Development, Santa Ynez Unit, Santa Barbara Channel,
Off California (Washington, D.C.: GPC, 1974).

34. Department of the Interior, U.S. Geological Survey, Final Environmental
Statement, Oil and Gas Development in the Santa Barbara ChanneT, Outer Continental
Shelf Off California (Washington, D.C.: GPO, 1076).

35. Federal Register, 40 (November 4, 1975), p. 51199.

36. U.S.C. 1333(f); 67 Stat. 463, 4(f).

37. 43 U.S.C. 1333(3)(1).

38. 29 U.S.C. 653(a).

39. 29 U.S.C. 651 et seq.

40. Mikeael F. Reitz, U.S.G.S., Ventura, personal communication to Bill Deller,
OCS Project staff; Lt. Commander Foster Thompson, Coast Guard, personal communication
dated November 29, 1976, to Bill Deller, OCS Project staff; J. Ray McDermott, OSHA,
personal communication dated December 1, 1976, to Bill Dell,er, OCS Project staff.

41. Don Kash, et al., op. cit., pp. 64-66.

42. 43 U.S.C. 1334(c), 43 C.F.R. Part 2883.

43. 49 U.S.C. l(l)(b).

160

44. 15 U.S. C. 717, 717 'f.

45. Don Kash, et al., op. cit., pp. 66-67.

46.. 33 U.S.C. 403, 43 U.S.C. 1333(f); 33 C.F.R. Part 209.

47. 33 U.S.C. 1344; 33 C.F.R. Part 209.

48. 33 U.S.C. 1413; 33 C.F.R. Part 209.

49. 49 C.F.R. Parts 190-195; 82 Stat. 720, 3a; 49 U.S.C. 1671 et seg.; 80 Stat.
937, 6; 18 U.S.C. 831-835; 49 U.S.C. 1655.

50. Maury Adams, U.S.G.S., April 5, 1977.

51. Don Kash, et al., op. cit., p. 63.

52. 33 U.S.C. 1224.

53. 33 U.S.C. 403, 43 U.S.C. 1333(f); 33 C.F.R. Part 209.

54. Letter from Resources Secretary Claire T. Dedrick to Col. Hugh G. Robinson,
Los Angeles District Engineer, December 2, 1976.

55. "U.S.C.G. Must Explain San Pedro--Sealane Stance," The Oil and Gas Journal,
74 (February 2, 1976), p. 52.

56. M. V. Adams, et al., op. cit., p. 24.

57. Ibid., p. 24.

58. Ibid., p. 25, 43 U.S.C. 1334(a)(1); 30 C.F.R. 250.50; Union Oil v. Morton
(9th Cir.-,1975) 512 F.2d 743, 749, citing Gulf Oil v. Morton (9th Cir., 1973) 493
F.2d 141. (Regulations relating to unitization are at 30 C.F.R. 250.50, and 30
C.F.R. Part 126.)

59. Paci f i c OCS Order 11 .

60. 30 C.F.R. Part 250.38.

61. 30 C.F.R. Part 250.93.

62. 30 C.F.R. Part 250.97, Federal Register, 41 (June 23, 1976), p. 25893.

63. Department of the Interior, U.S. Geological Survey, Final Environmental
Statement, Oil and Gas Development i n the Santa Barbara Channel, Outer Continental
Shelf Off California (Washington, D.C.: GPO, 1976), 111, pp. IV-33 to IV-37.

64. Ibid., pp. IV-35 to IV-38.

65. Pacific OCS Order 12, Michael F. Reitz, U.S.G.S., Ventura, personal com-
munication to Bill Deller, OCS Project staff.

161-

66. U.S. General Accountina Office, Outer Continental Shelf Sale #35--
Problems Selecting and Evaluatin6 Land to Lease (Washington, D.C.: GPO, 1977),
p. 29.

67. Ibid., pp. 30-31.

68. OCS Tract Selection for General Oil and Gas Lease Sales (GS-BLM), dated
August 19, 1971, reproduced in U.S. Department of the Interior, Requlations Pertain-
ina to Mineral Leasing, Operations and Pipelines on the Outer Continental Shelf
T-Washinaton: 1975), p. 75.

69. U.S. General Accounting Office, op. Lit., p. 20.

70. Ibid., D. 21.

71. 43 U.S.C. 1331 et sea.; 67 Stat. 462.

72. 43 U.S.C. 13.34(a)(1).

73. Union Oil Co. v. Morton (9th Cir., 1975) 512 F.2d 743, 749, citinq Gulf
Oil v-. Morton (9th Cir., 1973) 493 F.2d 141.

74. 43 U.S.C. 1334(b)(2), Nion Oil v. Morton (9th Cir., 1975) 512 F.2d, 743,
747.

75. 43 U.S.C. 1334(b)(1).

76. 43 U.S.C. 1334(a)(2).

77. 43 U.S.C. 1337(i).

78. 43 U.S.C.1334(a)(1); 30 C.F.R. Part 250.12.

79. Union Oil v. Morton (9th Cir., 1975) 512 F.2d 743, 750-751.

80. Ibid., p. 752.

81. Ibid., P. 749.

82. See memorandum of September 26, 1975, from Ja 'v L. Shavelson, Assistant
Attorney General, State of California, to Preble Stolz, Director, Office of Planning
and Research: and memorandum dated October 31, 1975, from Assistant Solicitor for
Minerals Frederick N. Ferguson on Authority to terminate OCS oil and cas leases.

83. Mic'hael A. Chartock, et al., North Sea Oil and Gas, Implications for
Future United States Development (Oklahoma City: 1975), p. 19.

84. Ibid., p. 22.

85. 16 U.S.C. 1451 et seq., as amended by P.L. 94-370, 90 Stat. 1013.

86. 30 C.F.R. Part 250; Don Kash, et al., op. cit., p. 152.

87. 43 U.S.C. 1334.

162

88. 5 U.S.C. 552.

89. 5 U.S.C. 552(b).

90. Pennzoil Oil v. Federal Power Commission (5th Cir., 1976) 53.4 F.2d 627.

91. Ibid., p. 632.

92. Ibid., p. 630.

93. Ibid.

94. Ibid., p. 632.

95. National Parks and Conservation Association v. Morton (D.C. Cir., 1974)
498 F.2d 765; Westinghouse Electric Corp. v. Schlesinger (46tF-Cir., 1976) 542 F.2d
1190 (U.S. appeal pending).

96. Charles River Park "A," Inc., v. Department-of H.U.D. (D.C. Cir., 1975)
519 F.2d 9@5, 942.

97. See Westinghouse Electric Corp. v. Schlesinger (4th Cir., 1976) 542 F.2d
1190, 1201, n 27 (U.S. appeal pending

98. See. e.g., Westinghouse v. Schlesinger, supra, and Charles River Park "A,"
Inc..v. Department of.H.U.D. (D.C. Cir., 1975) 519 F.2d 935.

99. See, e.g. Sears, Roebuck and Co. v. General Services Administration (D.C.
Cir., 1974) 509 F.2d 527; Grumman Aircraft Engin ering Corp. v. Renegotiation Board
(D.C. Cir., 1970) 425 F.2d 578; and M.A. Schapiro v. S.E.C. (DDC, 1972) 339 F.
Supp, 467.

100. Westi*nghouse v. Schlesinger,. s-upra.

101. FAA Administrator v. Robertson (1975) 422 U.S. 255, 45 L.Ed.2d 164, 95
S. Ct. 210.

102. Crown Central Petroleum Corp. v. Kleppe (Md. D.C., 1976) 424 F. Supp. 744.

103. Ibid., p. 752.

104. 30 C.F.R. Parts 250.97, 251, Federal Register, 41 (June 23, 1976),
pp. 25891-2589-7.

105. 30 C.F.R. Part 250.34.

106. Proposed OCS Order 15, Federal Register, 41 (October 20, 1976), p. 46355.

-107. 42 U.S.C. 4321 et seq.; U.S. Department of the Interior, Bureau of Land
Management, "Marine Environmental Study.Plan for the Southern California Outer
Continental Shelf Area Southern California Borderland Region," October 15, 1976,
pp. 2-3.

108. Ibid.

12-76658 163

109. Memorandum to Chairman, Outer Continental Shelf Environmental Studies
Advisory Committee from Donald Truesdale, Assistant Director, Minerals Management,
U.S. Department of the Interior, Bureau of Land Management, November 5, 1976.

110. Proceedings of the Recommendation for Baseline Research in Southern
California Relative to Offshore Resource Development, Southern California Academy
of Sciences, February 15, 1975.

111. Coastal Effects of Offshore Energy Development: Oil and Gas Systems,
Office of Technology Assessment, 1976.

112. Murray D. Dailey, Barbara Hill, and Neal Lansing, eds., A Summary of
Knowledge of the Southern California Coastal Zone and Offshore ArJs_,prepared
by the Southern California Ocean Studies Consortium of the California State
University and Colleges for the U.S. Department of Interior, Bureau of Land
Management (September, 1974).

113. Southern California Baseline Studies and Analysis, Quarterly and Sample
Inventory Report, Science Applications, Inc., January 30, 1976.

114. Southern California Marine Mammal and Bird Survey prepared by the Uni-
versity of Southern California at Santa Cruz and Irvine under Bureau of Land
Management Contract No. 08550-CT5-28.

115. Annual Report 1976, Outer Continental Shelf Environnental Studies Advisory
Committee, U.S. Department of the Interior, February 28, 1977, p. 132.

116. Ibid., p. 133.

117. Ibid., p. 42.

118. See Annual Report 1976, Outer Continental Shelf Environmental Studies
Advisory Committee, U.S. Department of the Interior, February 28, 1977, p. 7, for
discussion of origin, organization, and functions of National OCS Advisory Board
and Outer Continental Shelf Environmental Studies Advisory Committee.

119. See "Potential Petroleum Development on the Central and Northern Calif-
ornia OCS: The Need for a Coordinated Environmental Studies Program in a Frontier
Area," statement by Dr. James W. Rote, Assistant Secretary for Resources, Calif-
ornia Resources Agency, October 22, 1976; and Annual Report 1976, Outer Continental
Shelf Environmental Studies Advisory Committee, U.S. Department of the Interior,
February 28, 1977, for recommendations to improve the Environmental Baseline Studies
Program.

120. Bureaw of Land Management and Office of Coastal Zone Management, State
Information Needs (Washington, D.C.: GPO, 1976).

121. 'Personal communication from Ralph W. Johnson, Professor of Law, University
of Washington, to Suzanne Reed, Governor's Office of Planning and Research, July 7,
1977.

122. Cal. Govt. Code, �65100 et seq.

123. Cal Pub. Res. Code, �3000 et seq.

164

124. Cal. Pub. Res. Code, �30515.

125. 16 U.S.C. 1451 et

126. Coastal Zone Management Act, �307(c)(3).

127. "That a federally conducted or supported activity ... be ccnsistent
with a management program except to the extent that deviation therefrom is justi-
fied because: (1) some circumstance a -rose after the approval of the management
program which was not foreseen at the time of the approval, and (2) a consistent
action would thereafter impose an unreasonable burden on the federal agency in
relation to the negative impact of the deviation on the integrity of the manage-
ment program."

128. Federal Register, 41 (September 28, 1976), pp. 42887-42888), �921.5.

129. Correspondence from Charles R. Roberts, Executive Director, Bay Conser-
vation and Development Commission, to Robert Knecht, Director, Office of Coastal
Zone Conservation Commission, September 14, 1976.

130. Ibid.

131. Correspondence from Robert Knecht to Charles R. Roberts, October 13, 1976.

T32. Coastal Zone Management.Act, �307(c)(A).

133. Federal Register, 41 (September 28, 1976), p. 42883.

134. Coastal Zone Management Act, �303(a).

135. Federal Register, 41 (September 28, 1976), p. 42878, �921.1(p).

136. 30 C.F.R. Part 250.34(a)(b).

137. 30 C.F.R. Part 250.34(c).

165

CHAPTER 14

THE RESOURCE BASE:
EDUCATED GUESSES

It has long been known that the sedimentary basins off southern California
contain substantial amounts of recoverable oil and gas. In state waters, in fact,
recovery of oil and gas has proceeded siince 1896, and several fields have been in
continuous production for more than 50 years (Table 1). Develowent of the oil
and gas resources in state waters is now essentially complete. After peaking in the
late 1960s, production is now about 175,000 B/D oil and 60,000 MCF/D natural gas,
and will decline in the future, l/

Exploitation of the oil and gas resources in federal waters off California, how-
ever, is just getting underway, although the first California OCS leases were sold
in 1966 and 1968. Development of these leases was delayed for several years after
the Santa Barbara Channel blowout, and only two OCS fields are now in production,
producing about 40,000 B/D oil and 15,000 MCF/D natural gas. Exploratory drilling
has been undertaken on only @alf of.the 65 active leases in the Channel OUS.
Recently, the Interior Department lifted its restrictions, and the pace of exploration
and development in the Channel, is accelerating. In the 1980s, Channel OCS production
will exceed 100,000 B/D oil and 100,000 MCF/D natural gas, and could reach double
those amounts.

Lease Sale #35 opened up the remainder of the southern California OCS for oil
and gas development. Exploratory drilling is underway on the San Pedro Bay and
Tanner Banks leases. One discovery has already been certified by the U.S. Geological
Survey, 2/ and the prospects for additional discoveries are good. Another California
OCS lea*SE-sale has been proposed for the spring of 1978.

OCCURRENCE OF PETROLEUM

In order for an oil or gas field to exist, a series of general conditions must
obtain. 3/ There has to be a source rock in which the petroleum is formed,
a reservoi-r rock from which the petrol can be extracted, a cap rock which keeps
the petrol-eu-m--17-n the reservoir rock, and a structure or trap which concentrates the
petroleum within the reservoir rock.

Petroleum is created in sedimentary rocks. The original sediments must be rich
in organic compounds and must be buried before the organic material can be oxidized.
If the sediments are buried at sufficient depth (on the order of thousands of feet),
temperature and pressure will increase to the point where the organic compounds are
converted into petroleum hydrocarbons. The nature of the hydrocarbons formed --
oil, gas, condensate, etc. -- depends on the temperature and pressure in

167

TABLE 1
CALIFORNIA TIDELANDS OIL AND GAS FIELD STATISTICS*

YEAR YFEAPR 1975
OF FIRST 0 EAK PEAK ANNUAL PEAK DAILY AVERAGE DAILY
FIELD PRODUCTION PRODUCTION PRODUCTION PRODUCTION PRODUCTION CUMULATIVE PRODUCTION EST17@!ATED RESERVES

Oil Gas oil Gas Oil ras
SANTA BARBARA CHANNEL (R/D) (MCF/D) (B/0) (MCF/D) (B/0) (MCF/D)
Alegria 1962 1970 77,033 BBL 211 B/D 81 213 451,434 3,382,167 392,000 468,OuO
Caliente 1962 1967 4,284,901 MCF 11,740 MCF/D - 948 - 3,646,417 - 2,385,000
Carpinteria 1966 1969 10,435,543 BBL 28,590 B/D 3,979 4,742 22,207,611 19,234,051 12,133,000 10,919,000
Coal Oil Point 1961 1966 232,136 BBL 636 B/D 37 122 1,289,085 3,178,884 81 'OUO 201,000
Elwood 1929 1931 7,769,859 BBL 21,287 B/D 115 542 76,475,704 66,171,624 30,000 1,328,000
Gaviota 1960 1964 8,994,473 MCF 24,692 MCF/D - 8 - 69,921,000 - 279,000
Molino 1962 1967 30,576,437 MCF 83,771 MCF/D - 9,242 - 223,771,366 140,000 13,829,OUO
Point Conception 1965 1970 153,617 BBL 420 B/D 209 107 842,486 330,245 580,UOO 200,000
Rincon 1928 1960 1,271,457 BBL 3,483 B/D 1,094 576 29,841,999 31,279,409 6,158,000 1,103,000
cyl South Elwood 1965 1968 1,929,085 BBL 5,285 B/D 3,277 - 9,903,377 7,689,900 63,182,000 89,848,OOU
00 Summerland 1958 1964 3,792,551 BBL 10,390 B/D 711 3,639 24,478,351 85,075,136 6,585,000 19,816,000
West Montalvo 1953 1958 608,693 BBL 1,668 B/D 235 - 5,322,056 3,242,723 578,000 -
9,738 20,139 171,000,000 717,000,000 90,000,000 132,00,000

LOS ANGELES BASIN

Belmont 1947 1968 4,295,682 BBL 11,769 B/D 6,720 1,647 41,226,757 31,567,/88 11,637,OuO 3,532,000
Huntington Beach 1930 1972 16,092,650 BBL 45,733 B/D 36,820 4,896 445,772,417 287,511,711 104,278,000 15,888,000
Torrance 1956 1958 857,170 BBL 2,348 B/D 1,256 1,690 5,474,590 4,646,906 2,826,000 3,983,000
Venice 1966 1968 445,162 BBL 1,247 B/D 320 134 2,178,868 1,223,105 321,000 172,000
West Newport 1953 1957 352,539 BBL 966 H/D 287 107 4,024,187 1,309,848 979,000 270,000
Wilmington 1939 1969 64,775,754 BBL 177,468 B/D 120,836 26j966 835,953,144 437,695,427 366,047,000 98,157,uOO
SUB-TOTAL 166,249 35,440 1 335,000,000 764,000,000 486,000,000 122,600,000

GRAND TOTAL 175,987 55,579 1,506,000,000 1,281,000,000 576,000,000 254,000,ouo

*Statistics supplied by California Division of Oil and Gas, California State Lands
Division, and the Conservation Committee of Calffornia Oil Producers.

the source rock, as well as the length of time the organic compounds are exposed
to these conditions. For example,, heavy crude oils are thought to be relatively
"young" hydrocarbons, while natural gas and carbon are regarded as more "mature."

After formation, some petroleum hydrocarbons may migrate from their
original source rock locations, either through pole spaces in the rock or along
fractures caused by faulting orother tectonic activity. If not blocked by im-
permeable rock layers, hydrocarbons may reach the surface of the ocean floor to
form natural seeps. Thousands of natural oil and/or gas seeps exist both offshore
and onshore in Southern California.

The rock from which oil or gas can be produced is called reservoir rock. Rocks
of reservoir quality exhibit three main characteristics. They have relatively high
porosity with open spaces between their constituent mineral grains where fluids
may collect. They have relatively high permeability, with the pore spaces inter-
connected so that fluids can move th"rough the rock. Finally, there must be an
impermeable cap rock overlying the reservoir rock to contain the oil and gas within
the reservoir rock. Three fluids are often found in reservoir rocks: oil, gas
and salt water. Gas, lightest of the three, tends to occupy the highest possible
position in the reservoir. Water, the heaviest, tends to lie in the lowest position,
with oil somewhere between the two. Sandstone is the most common reservoir rock
in California, although fractured shales are prominent in recent discoveries.

The final requirement for the existence of petroleum in commercial quantities is
a structure or trap, which accumulates the petroleum. Traps may be structural in
origin -- folds, anticlines, domes -- or stratigraphic, or they may occur as a
result of faulting activity. Faulted anticlines are the most common trap in
California offshore oil and gas fields discovered to date. Oil and gas fields often
contain more than one producing zone, and may be formed by more than one kind of
trap.

C A L I F 0 R N I A 0 F F S H 0 R E

The southern California OCS is structurally unique among the OCS areas of the
United States. Extensive and continuing tectonic activity during the last 20 million
years has created a complex pattern of ridges and basins interlaced by a series of
active and inactive fault systems. The southern California offshore can be divided
for discussion purposes into the Borderland and the Santa Barbara Channel, with
the Santa Barbara Channel Islands separating these two distinct regions.

BORDERLAND

The Borderland is characterized by numerous ridges and basins, which in their
NW/SE alignment lie generally parallel to the Peninsular mountain ranges on the
mainland. 4/ Topographic relief is as much as 7,500 feet, with elevations ranging
from almos-f 1,500 feet above sea level to more than 6,000 feet below sea level. The
Borderland itself can be divided into the inner basin area and the outer basin area,
separated by the ridge system which includes Santa Catalina Island. The inner basin
area includes Santa Monica and San Pedro basins and the San Diego trough. The Santa
Monica and San Pedro basins, as extensions of onshore basins with extensive petroleum
development, are considered the most promising areas for petroleum discoveries in
the Borderland. The Santa Monica basin was excluded from OCS Sale #35. The San
Pedro basin tracts, however, were included, and they received the hiqhest bonus bids.
They were also the first OCS Sale #35 leases to underao exploratory drillinq.

The petroleum potential of the outer basin area is essentially unknown, in part
because the prospective sedimentary basins are not extensions of known coastal basins,
and in part because of the great depths encountered in much of the area.

169

Over 90 % of the Borderland lies in depths greater than 200m (656 feet), and
much of it in depths exceeding 500m ( 1,640 feet). -5/ The world's tallest production
platform, recently installed in the Santa Barbara Channel, rises from a depth of
267m (867 feet). Thus, most of the borderland -- including all of the-sedimentary
basins in the outer basin area -- is beyond the reach of existing or anticipated
production systems. Reflecting this constraint, the leases offered in OCS Lease
Sale #35 and considered for OCS Lease Sale #48 lie near shore or along the crests of
the ridqes and banks separating the basins (see Fiqure 4 in Chapter 22).

The Deep Stratigraphic test well drilled on the flank of the Cortes Ridge,
together with limited core samples, provide some information on the petroleum
potential of the outer basin area. 6./ The conditions which have permitted substantial
oil and gas recovery from the Los Angeles and Ventura coastal basins -- thick sedi-
mentary sections and turbidite reservoir sands -- appear not to exist seaward of
Santa Catalina Island. Thus, while petroleum may be found in the outer basin area,
it will not be found under the same conditions as in the highly-productive coastal
basins. 7/

Potential source and reservoir rocks do, however, exist in the outer basin, and
commercial oil and gas fields may well be found. The prospective formations in the
outer basin ridges are generally older than their counterparts in the coastal basins.
This suggests that outer basin discoveries could be comparatively high in natural
gas.

SANTA BARBARA CHANNEL

As the DeDartment of Interior notes, "the Santa Barbara Channel is a tectonic
depression that forms the westward extension of the Ventura basin and a submerged
Dart of the Transverse Ranqe province of southern California." 8/

The Channel is an established petroleum province, with 13 offshore oil and gas
fields now in production. More than 1,100 offshore wells have been drilled, with
some 250 completed as production wells. 9/ Most oil has been taken
from upper Miocene and Pliocene sandstones, well over 10,000' thick in the eastern
Channel. Dry gas fields have been found only in the western Channel tidelands,
where the Pliocene sandstones are much thinner, and where older formations are
prospective. Similarly, western Channel OCS discoveries exhibit high gas-oil ratios
compared to most eastern channel fields. Monterey fractured shales, which heretofore
contributed a very small percentage of production from the Channel region, are the
basis for the recent Santa Ynez and Santa Clara unit discoveries and for the ex-
pected production increases from the South Elwood field in the Channel tidelands.

The petroleum geology of the shallower portions of the Channel, especially the
near-shore eastern channel areas, is reasonably well-known. Deeper water areas --
primarily the central and western channel OCS -- are much less well-known, probably
because production technology for these deeper waters does not now exist, but also
because the rest of the Channel contains comparable or better prospects in much
shallower water'.

The leasing patterns in the Channel reflect the generally high petroleum potential
of the area, and the problem posed by water depth. Practically all of the tidelands
are leased and developed, or reserved in petroleum sanctuaries. Almost half of the
Channel OCS.has been leased, with most of the leases in the near-shore and eastern
portions of the Channel.

170

Almost all unlease.d OCS tracts lie in the central and western channel, roughly
between Coal Oil Point ahd-Point Conception. Despite the relatively great -
depths (up to 1,900 ft.) all of these tracts were nominated by oil companies for
inclusion in proposed Lease Sale #48, and may be offered for sale in 1978.

IHISTORY 0 F CALIFORNIA OFFSHORE PRODUCTION

T I D E L A N D S

Offshore production began in California -- and in the United States -- in 1896
in the Santa Barbara Channel, when wells were drilled from piers into the old
Summerland field. 10/ The State was neither issuing leases nor collecting royalties,
and these wells were drilled under lease from the littoral owners. Drilling was
entirely.unrestricted until 1921 when, with passage of the California Mineral
Leasing Act, the state began issuing permits for oil and gas exploration in the
tidelands and submerged lands. The Rincon field was discovered in 1927, and the El-
wood and Capitan fields in 1929.

The California Supreme Court's 1928 decision in Boone vs Kingsbury effectively
stripped the State of the power to reject permit applications for tidelands pros-
pecting. Immediately thereafter, the Legislature imposed an interim moratorium on
further tideland leases or permits. In 1929, as a result of substantial crude oil
overproduction and related beach despoliation, the Legislature prohibited altogether
the issuances of new leases for mineral extraction from tide or submerged lands.

In 1851, California began granting tide and submerged lands to poJitical sub-
divisions of the state, to be held.in trust for general commerce, navigation,
fisheries and recreation purposes. The City of Long Beach received such a grant
in 1911. In 1932, the Wilmington field was discovered, and.subsequently found
to extend offshore into the tide and submerged lands granted to Long Beach. The
California Supreme Court ruled in 1938 that Long Beach had the right to develop
the tideland oil reserves,-and in 1939 the Long Beach Oil Development Company
completed the first production well on such a tideland grant.

In 1938 and 1939, the Legislature created the State Lands Commission and placed
the administration of all state lands under its jurisdiction. The Commission was
allowed to issue exploration permits, but new oil and gas production Viere allowed only
where the State's submerged lands were being drained by wells on adjacent lands not
owned by the State.

During this period, it was generally assumed that the tidelands -- the land
between high tide and low tide -- belonged*to the adjacent state. As well, most
coastal states believed that they owned the submerged lands out to three miles off-
shore. After World War II, with technology developing to produce oil and gas in
ever greater depths, the question of federal-state ownership of offshore
resources emerged as a major issue. The Supreme Court ruled in 1947 that the federal
government held paramount rights to the lands and minerals of the three-mile strip
off the coast of California. Shortly thereafter, an Interim Agreement was negotiated
between California and the United States to permit existing offshore operations to
continue pending further litigation and possible Congressional action. Under this
agreement, the State Lands Commission continued to administer the three-mile strip,
with all revenues held in escrow. ll/

In 1953, Congress passed the Submerged Lands Act and the Outer Continental Shelf
Lands Act. The first returned jurisdiction of the three-mile strip to the adjacent

171

coastal state, whi,le the second established a framework for federal administration
of the submerged lands lying seaward of the three-mile boundary. The California
Legislature responded in 1955 with the enactment of the Cunningham-Shell Act, under
which these state offshore lands were opened up for exploration and development.

The Cunningham-Shell Act represented a compromise between the interests
advocating on the one hand, unrestrained offshore oil development and on the other,
preservation of the scenic and economic values of California's highly-developed
coastal zone. State land could be leased, provided that probable drainage of oil or
gas from state lands could be demonstrated. The 1955 Act restricted the issuance
of new leases to the tidal and submerged lands lying between the City of Newport
Beach and a point six miles south of the town of Oceano in San Luis Obispo. Further,
certain scenic coastal lands -- and the adjacent state waters -- in Los Angeles,
Santa Barbara, and San Luis Obispo counties, and San Clemente and Santa Catalina
islands were excluded from future leasing, except where probable drainage could be
demon'strated. Finally, the oil and gas resources in state waters from Newport Beach
south to the Mexican border were required to be developed by slant drilling from
onshore sites, wherever necessary to preserve and protect the highly developed
recreational and residential areas.

The 1938 Act provided that wells could be drilled into the state tidelands only
from the uplands or from filled lands. A court's liberal interpretation of the
term "filled lands" led to deliberate fill-in for the purpose of oil production.
Belmont Island was constructed in 1954 to develop the Belmont offshore field.
Similarly, Rincon Island was constructed in 1958 to tap the offshore portion of
the Rincon field. The Cunningham-Shell Act enlarged the lease terms to permit
drilling from platforms or other fixed or floatinq structures in, on, or over the tidal
and submerged lands. In 1958, Chevron and Exxon installed platform Hazel in the
Summerland offshore field, the first such platform to be installed in state waters.

0 U T E R C 0 N T I N E N T A L S H E L F ( 0 C S

For many years, the boundary between state tidelands and federal OCS lands in the
Santa Barbara Channel was in dispute. California argued that the Channel waters
constituted "inland waters", so that the three-mile line separating state and federal
jurisdiction should be drawn seaward of the Channel Islands. The federal government
disagreed, arguing that only the waters and submerged lands for a distance of three
miles off the mainland and around each island fell under state jurisdiction. In
1965, the U.S. Supreme Court settled the dispute in favor of the federal government,
clearing the way for federal leasing in the Channel OCS.

Before 1965, California had permitted core holes to be drilled in the disputed
area of the channel. Information gathered from these wells was closely guarded by
the sponsors of each well. In order that a greater number of potential lessees
would have comparable information, the Interior Department allowed 53 core holes to
be drilled in the Channel OCS between November, 1965 and February, 1968, in the
same locations as the earlier state-sanctioned core holes. 12/

The Carpinteria field lies partly in state waters and partly in federal waters.
The state portion was brought into production in 1966. This created the possibility
of drainage of the federal portion of the field from the state portion. To protect
against this, the Interior Department issued on January 1, 1967, a lease for the
federal portion of the Carpinteria field. This was the first California OCS lease.

On February 6, 1968, 71 additional Santa Barbara Channel OCS leases were sold.
Excluded from the sale was the area extending two miles seaward of the Santa Barbara
Petroleum Sanctuary, which was set aside as a Federal Ecological Preserve. Within

172

s,ix weeks of the lease sale, discovery of the Dos Cuadras field was announced.

On January 29, 1969, a blowout occurred at Union's Platform A in the Dos
Cuadras field, resulting in a major oil spill. 13/ In response, theSecretary of
the Interior 1)'suspended for several months alTdrilling and production activities
on Channel OCS leases (affecting six leases); 2) conducted a safety clearance
review'of the remaining leases; and 3) established a buffer zone contiguous to and
seaward of the Federal Ecological Preserve. Subsequently, the Interior Department
turned down applications by Union and Sun to install production platforms in the
Dos Cuadras and Carpinteria fields.

Aside from the Dos Cuadras and Carpinteria fields, 15 discoveries or extensions
have been announced on the Channel OCS leases. Exxon submitted an initial develop-
ment proposal for the Hondo field in the Santa Ynez Unit to USGS in 1971. After
lengthy review and the release of an Environmental Impact Statement (EIS) on the
proposal, the Interior Department approved the plan in 1974. USGS released an EIS
on Channel OCS oil and gas development in 1976. In January, 1977, Interior
Secretary Kleppe announced his decision that "development of existing oil and gas
leases in the Santa Barbara Channel should proceed in accord with existing laws
and regulations." -14/ Development proposals for the Hueneme and Santa Clara Unit
discoveries have b@e_n submitted to the Geological Survey and are now pending.

In December, 1975, the Interior Department held OCS Sale #35 and sold 56
additional California OCS leases. Of these leases, 13 lie in the San Pedro basin,
with the remainder in the outer basin area., Exploratory drilling has begun, and a
commercial discovery has been announced by USGS for one of the San Pedro basin
leases. 15/

Another California OCS Lease sale is proposed-by'.the Interior Department to be
held in the spring of 1978. The area of interest includes both the Santa Barbara
Channel and the Borderland.

PRESENT STATUS

T I D E L A N D S

Development of the state's oil and gas resources off Southern California is
essentially complete. Fifteen oil fields and three gas fields are now in production
in state waters served by nine platforms, seven artificial islands, and 42 sea-
floor production systems, as well as numerous onshore wells slant-drilled to ta
offshore fields. State offshore gas production peaked in 1968, oil production in
1969. Average daily production in 1975 amounted to 170,723 B/D oil and 53,046 MCF/D
natural gas and will decline in the future. Figure 1 shows the location of all
California's tidelands oil and gas fields.

0 C S

Development of UCS oil and gas resources off.California is just beginning.
Exploratory wells have been drilled on only 40 of the 121 active OCS leases off
California. Two fields -- Dos Cuadras and Carpinteria -- are in production, and in
1975 produced about 40,000 B/D oil and 15,000 MCF/D natural gas. Six production plat-
forms have been established, and development plans calling for installation of
four more platforms have been submitted to USGS. Seven commercial discoveries have
been announced by USGS -- six in the Santa Barbara Channel, and one in the San Pedro
Basin. California OCS oil and gas production is certain to rise sharply in the early
1980s as these discoveries are brought into production.
173

FIGURE 1:
CALIFORNIA'S TIDELANDS OIL AND GAS FIELDS

SANTA NARDARA COUNTY STATE OF CALIFORNIA
STATE LAND S DIVISION
VENTURA COUNTY OFF S HOR E 0 1 L RESOURCES

STAT E OFFSHORE LEASES
-7

LOS ANGELES COUNTY

Lot .."It 6

411-
6A.CT-11 odc I... 'i.1
:.*I M

GRA.1 ID C111 DI: 0RANGE COU06TY
.6c 66'..3 1.)

c s."T. G..c. LQ"K..
ar
too= st.c.
PAL02 V94DIS ISTAT14 T

GOWID L..DS 'ro*o A" I
T LOS -6iLIG

E.c.

or.,

Source: Hydrocarbon Potential of California's Offshore Lands.
State Lands Division, 1976.

PROSPECTS

Petroleum resources are distinguished from petroleum reserves on the basis of
discovery through exploration or development drilling. Oil and gas discovered or
thought to exist on the basis of such drilling we consider to be petroleum reserves.
Oil and gas whose existence is suspected but not yet demonstrated by such drilling,
we consider to be petroleum resources. We define the terms used in this report as
follows:

Petroleum resources: the oil and gas not yet discovered but thought to
exist in favorable geologic settings, and estimated to be economically
recoverable;

Proven petroleum reserves: the estimated quantities of crude oil and
natural gas which geologic and engineering data demonstrate with reasonable
certainty to be recoverable under existing economic and operating conditions
from known reservoirs; and

Inferred petroleum reserves: reserves eventually to be added to known fields
through extensions, revisions, and new reservoirs ( 11pays"). 16/

All of the oil and gas thought to be recoverable from the leases sold in Lease
Sale #35 are considered resources, and for these we present the resource estimates
published by USGS and the Western Oil and Gas Association. 17/ Similarly, we
consider the oil and gas believed to exist in the Santa Barlb-ara Channel OCS in
unleased areas or in leases without USGS-certified discoveries to be petroleum
resources, and not reserves. The oil and gas estimated to be recoverable from
existing fields or from certified discoveries in the Channel OCS we treat as reserves.
We classify as proved reserves the oil and gas estimated to be recoverable from the
fields now in production and those discoveries for which operators have submitted
development proposals to USGS. The oil and gas estimated recoverable from the
remaining discoveries we classify as inferred reserves.

R E S 0 U R C E E S T I M A T E S

Resource estimates amount to educated guesses as to the amount of oil and
gas which might be recovered from a given area. The most certain method of deter-
-mining whether economic concentrations of oil and gas exist in an area is to drill,
at a cost of several million dollars each, a series of exploratory wells. In
the absence of such direct and site-specific exploratory drilling information, it
is possible to construct resource estimates on the basis of indirect and general
information, but estimates of this kind must rely on incomplete knowledge and a
chain of assumptions which may or may not be valid. Great caution must be exercised
in their use.

Nonetheless, resource estimates are widely used despite their limitations,
because the stakes involved in offshore oil and gas development are so high. The
federal government itself makes and uses resource estimate 's to help decide which
OCS areas to offer for lease, to determine the fair market value of each tract
offered, and to project potential environmental effects. Oil companies also make
and use resource estimates to nominate tracts for leasing, to formulate bids, to
set exploration priorities (the best prospects are usually explored first), and to
make investment decisions. State and local governments historically have not made
resource estimates for federally controlled OCS areas because of the considerable
expense involved, the absence of directfinancial benefit from OCS production, and
175

their lack. of control over OCS operations. Rather, they rely on the estimates
produced by the Department of the Interior and other groups to anticipate onshore
activities and effects, and to some extent, to determine political-and philosophical
attitudes towards OCS development.

In simplified form, resource estimates are constructed in four steps:
1. identification of basin and rock types;
2. identification of structures;
3. estimates of oil and gas in place;
4. estimates of the oil and gas capable of being recovered. 18/
Resource estimates may be presented either as a single set of numbers -- one each
for potentially recoverable oil and gas -- or as pairs of numbers, representing
low-range and high-range estimates for both oil and gas. Resource estimates pre-
sented in low-range/high-range format sometimes (but not always) include "confidence"
limits. When confidence limits are included, the low-range estimate is usually
associated with 95 % confidence, the high range estimate with 5 % confidence.

Information used to make resource estimates comes from a variety of sources.
The USGS'conducts regional geologic studies, with emphasis on proposed leasing
areas. These studies include sampling and analysis of rock outcrops on the sea
floor and the preparation of maps describing the surficial geology of the areas.
But surficial qeology provides very limited information on prospective oil and
gas reservoirs, which usually lie thousands of feet below the sea floor.

Three geophysical methods are commonly used to obtain information-on sub-
surface geologic conditions. Magnetic surveys help define the characteristics
of sedimentary basins, including the thickness of sediments and the presence and
general location of structural features and faults. Gravity surveys provide addi-
tional information on the structure of sedimentary basins. Seismic reflection
surveys supply structural and stratigraphic information with greater precision,
and specificity than either gravity or magnetic studies. USGS, oil companies and
independent contractors all conduct geophysical surveys of these types in prospective
leasing areas. In the Southern California OCS, USGS alone had gathered 18,000
miles of seismic lines, and even more gravity and magnetic data, by September
of 1975. 19/

As noted, some nearshore portions of the California OCS, specifically the
Santa Barbara Channel and the San Pedro basin, are considered extensions of
onshore or coastal sedimentary basins. The onshore and tidelands portions of
these basins have produced oil and gas for many years, and their petroleum geology
is reasonably well known. Also, some direct information is available from existing
OCS leases in the Channel and from core holes drilled in the 1950s and 1960s in
the Channel and the San Pedro basin. For these reasons, resource estimates for
the unleased OCS portions of these two areas can be made with a greater degree of
confidence than is usually possible.

Other parts of the California OCS, such as the Tanner and Cortes Banks, are
essentially unknown. These areas are geologically distinct from onshore or coastal
basins, so that no extrapolation is possible, and little or no exploratory drilling
information is available. In such "wildcat" areas considered or offered for lease,
oil companies may form a consortium to drill a deep stratigraphic test well, as
was the case on the flank of the Cortes Bank in 1975. Present USGS policy requires
that such wells be drilled "off-structure,"where oil and gas are least likely
to be found. From this type of well, the stratigraphy of the sections encountered
can be determined and correlated with seismic reflections and with the individual
strata identified from bottom samples collected in the actual prospect areas.
Geologic and chemical analyses are conducted on samples of all strata encountered
to determine their suitability as petroleum source or reservoir rocks. Much of this
information can be extrapolated to the tracts offered for lease.
176

LEASE SALE NO. 35

Prior to Lease Sale #35, the two most widely circulated sets of resource
estimates for the sale areas were those of the USGS and the Western Oil and Gas
,Association (WOGA) a trade association for the oil and gas companies operating in
Southern California.

USGS estimated recoverable oil and gas in the areas offered for lease at
1.25 - 2.25 billion barrels of oil and 1.9. - 4.0 trillion cubic feet of gas,
distributed as follows:

TABLE 2:
USGS LEASE SALE NO. 35 RESOURCE ESTIMATES 20/

Area Millions BBL Oil Million MCF Gas

San Pedro Bay 709 - 946 602 - 821
Santa Rosa Cortes 242 - 431 603 - 1,108
(North)
Santa Rosa Cortes 239 - 660 613 - 1,785
(South)
Santa Barbara - 67 - 219 103 - 342
Santa Catalina

The Western Oil and Gas association released a report in October, 1974,
predicting 6 - 19 billion barrels of oil potentially recoverable, with 14 billion
barrels the "most likely" amount. 211

The wide discrepancy between the two sets of estimates is not hard to
explain. WOGA was notactually making its own resource estimates, nor did it use
the proprietary company information. In 1971, Frank Parker, a consulting geologist,
estimated that the Southern California OCS contained 75 billion barrels of oil in
place. 22/ WOGA took Parker's estimate, scaled it down to 54 million barrels to
cover @-he 7,700,000 acre "call for nominations" area of Lease Sale #35 and
applied a recovery factor of 25 % +- to arrive at its 14 billion barrel "most-
likely" estimate. When the 1,300,000 acres actually offered for lease were identified
WOGA reduced its 6 - 19 billion barrel estimate to "range from about 10 billion
barrels downward, depending upon the correlation adjudged between these tracts
and Parker's potential petroleum areas." 23/ In any event, WOGA's stated purpose
was not to estimate as accurately as availTble information permitted the amount
of o-i-l-and gas to be recovered from the Lease Sale No. 35 tracts, but to posit
the highest possible yield of offshore oi-I and gas, so as to evaluate'the maximum
possible environmental impacts stemming.from recovery. Their primary concern
was to avoid criticism for understating potential impacts. 24/ In addition, WOGA
was not a disinterested party and may have felt that publicizing this very high
estimate would supply Interior with stronger reasons for holding Lease Sale #35,
despite widespread state and local opposition. 25/

USGS, on the other hand, was attempting to make as accurate an estimate
as it could. USGS based it's E@s-timates on all the data and information
available to it in 1974, including Parker's 1971 paper. The USGS estimates pertain
to the actual 1,300,000 acres offered for lease, not to the 7,700,000 acre "call
for nominations" area. Further, the USGS estimates do not rule out a yield greater
than 2.25 billion barrels of oil; they simply assign to this possibility of less
than one in 20. Inasmuch as only 310,000 of the 1,300,000 acres offered for lease
were actually sold, both sets of estimates are probably high. Of the two, however,
the USGS estimates must be considered more reliable.
177

In the Lease Sale #35 Final Environmental Statement, the Bureau of Land
Management (BLM) presents the followi.ng set of low-range and high-range estimates:

TABLE 3:
BLM LEASE SALE NO. 35 RESOURCE ESTIMATES 26/

Area Million BBL Oil Milli.onMCF Gas

San Pedro Bay 709 - 6,259 602 - 7,023
Santa Rosa Cortes 242 - 2,136 603 - 7,035
(North)
Santa Rosa Cortes 239 - 2,110 613 - 7,152
(South)
Santa Barbara - 67 - 591 103 - 1,202
Santa Catalina
Total 1,257 - 11,096 1,921 - 22,412

These BLM numbers re 'present a compromise between the LISGS and WOGA estimates.
The USGS "low-rnnge" estimates have been used for the low range; WOGA's 14 billion
barrel estimate is used for the high range. The rationale for this compromise is
not clear. It may be that BLM, as did WOGA, used the extremely high estimates in
order not to be accused of understating the potential effects of the development
activities. In view of the highly charged atmosphere surrounding the eVents cul-
minatina in Lease Sale #35, BLM may have believed it politic to publish estimates
embracing both divergent sets of estimates.

The final Environmental Statement on Santa Barbara Channel oil and gas
development presents yet another set of resource estimates for the Lease Sale
#35 tracts,adjusted, according to the text, to reflect the actual tracts
leased:

TABLE 4:
USGS LEASE SALE NO. 35 REVISED RESOURCE ESTIMATES 27/

Area Million BBL Oil Million MCF Gas

San Pedro Bay 355 - 3,310 301 - 3,500
Santa Rosa Cortes 100 - 850 240 - 2,800
(North)
Santa Rosa Cortes 120 - 1,555 310 - 3,580
(South)
Santa Barbara - 13 - 120 20 - 240
Santa Catalina
Total 588 - 5,655 781 - 10,120

The analytical basis for these figures. is not stated, though the numbers appear
to be modifications of the earlier BLM compromise between USGS and WOGA figures.
USGS personnel have informally indicated to the OCS Planning Project that these
figures were hurriedly assembled in the-final days before publication of the document
and were not based on a rigorous analysis. 28./

For planning purposes, state and local officials need the most reliable resource
estimates available. With respect to'Lease Sale #35, the question is whether-WOGA
or USGS estimates are more. reliable. On the basis of the limited information

178

in the public domain, it seems clear that the original USGS estimates are more
dependable than those of WOGA. The California State Lands Division independently
reviewed both sets of estimates and concluded-that USGS estimates were "reasonable
and acceptable." 29/ WOGA has stated that its estimates did not draw on proprietary
information, and T-hat its figures "may be too high to use in estimating the amount
of oil and gas that may be produced." 30/ In Parker's own words, his overall value
of 75 billion barrels of oil is "a fai_@_estimate if the thickness and extent of the
Pliocene and upper Miocene strata are as shown on the maps and sections. However-,
these critical factors are based on scanty information and liberal interpretations."
As USGS points out in a 1976 review of the petroleum potential of the Southern
California OCS:

These strata are now known to be much thinner and of more limited.
area than inferred by Parker, and he was unaware that older sediments
were widely exposed over much of the truncated Santa Rosa Cortes Ridge.
The immaturity of potential source rocks was not known, and the presence
of adequate reservoir sands was given little discussion. Parker's
estimates were based largely on comparisons with the Los Angeles.basin,
i@ questionable premise in consideration of our present knowledge. 31/

In September, 1975, Dr. J. C. Taylor of the USGS presented data suggesting
that.the southern.California OCS oil and gas prospects were poorer than previously
suspected. 32/ In view of these pieces of evidence, the OCS Planning'Project
concludes th@_t the USGS resource estimates are the best figures available for the
tracts sold in Lease Sale #35. For planning purposes, we shall use the following
figures:

TABLE 5:
LEASE SALE NO. 35 RESOURCE ESTIMATES 33/

Area Million BBL Oil Million MCF Gas

San Pedro Bay 355 - 946 301 - 821
Santa Rosa Cortes 100 - 431 240 - 1,108
(North)
Santa KOsa Cortes 120 - 660 310 - 1,785
(South)
Santa Barbara 13 - 120 20 - 240
Santa Catalina
Totals 588 - 2,157 871, - 3,954

SANTA BARBARA CHANNEL OCS

Resource estimates have been published by the Interior Department for existing
leases in the Channel OCS without discoveries, and for Channel OCS tracts which
have not yet been leased: 34/

Existing Leases With-out Discoveries: USGS has estimated that the existing
Th-'annel OCS Leases without-iiscoveries may contain 40-200 MMB of recoverable
oil and 20-100 BCF of recoverable-natural gas; and,

Unleased Channel OCS Tracts: About half of the Channel,OCS-is avail.able for
Te_ai_s@ing, but not now leased.- The enthusiastic response-of the oil-industry to
the call for nbminations for proposed Lease Sale #48'underscores the petroleum
potential of the unleased Channel-OCS tracts.. The Interior Department has is-
sued conflicting resource estimates for these unleased tracts. In its 1976 Final.
Environmental Impact Statement on Channel oil and gas:development, USGS estimated

13-76658 179

the unleased tracts to contain 40-150 MMB of recoverable oil and 20-70 BCF of
recoverable gas. 35/ In a December, 1976, briefing on proposed Lease Sale #48
BLM estimated unleased Channel OCS tracts to contain 30-900 MMB recoverable
oil and 7-525 BCF recoverable gas. In his January 6, 1977, press release,
Interior Secretary Kleppe estimated those tracts to contain 40-50 MMB recover-
able oil and 20-70 BCF recoverable gas. 36/ The State of California cannot
determine which of these estimates renre@_ents Interior's best thinking. For
planning purposes, the OCS task force will use the middle estimate: 40-150
MMB recoverable oil and 20-70 BCF recoverable natural gas.

R E S E R V E E S T I M A T E S

If an exploratory well encounters hydrocarbons, the operator conducts
tests to determine the flow rates and the physical characteristics of the producing
formation(s). If the test results are encouraging, the operator drills
wells to determine the configuration of the prospective field. When this exploration
program is completed and the reservoir's physical characteristics have been determined,
it becomes possible to estimate the discovery's reserves, the amount of oil and
gas capable of being.produced from the discovery. 37/

The first step is to estimate the area and thickness of the productive zone
or zones. Since exploratory wells are often widely spaced, there is room for
considerable interpretation, and allowance must be made for variations in thick-
ness throughout the reservoir. The volume of the reservoir, multiplied by the
effective porosity of the producing formation(s), determined by laboratory analysis
of core samples or by well-logging devices, yields the reservoir capacity.
The percentage of a reservoir's pore spaces occupied by oil (rather than
water) is called the reservoir's oil saturation, and commonly varies between 50 %
and 90 % of the total liquid in the reservoir. Reservoir capacity, multiplied by
the oil saturation percentage, gives an estimate of the oil-in-place in the
reservoi r.

However, much of the oil-in-place in a reservoir cannot be extracted. The
recovery factor, or percentage of oil-in-place which can be produced, varies from
less than 10 % to more than 50 %, averaging for all oil fields in the United States
about 32 %. -Every oil field has a different recovery factor, depen 'ding on the
geologic characteristics of the reservoirs, the physical properties of the oil
itself, the drive mechanism pushing the reservoir's oil to the well bore, the
operator's production methods, and production costs in proportion to the selling
price for the produced oil. California crude oils are usually heavier and more
viscous than the crude oils produced in the rest of the country. This is one
reason why the recovery factor in the average California oil field -- roughly 24 %
for all fields and 10 % for offshore fields -- is below the national average.

There are four kinds of reservoir drive mechanisms which push oil toward a
producing well: dissolved gas dri ve, powered by the expansion of natural gas
coming out'of solution in the oil as production reduces reservoir pressure; water
drive, created by the movement of water into the reservoir as reservoir pressure
decTi-nes; gas cap drive, where a gas cap expands into the oil reservoir as reservoir
pressure falls; and gravity drive, which occurs in steeply-dipping, highly permeable
reservoirs. Most oil fields exhibit several kinds of drive mechanisms. The recovery
factor is different for each kind of drive mechanism, as shown in Table 6:

180

TABLE 6:
PRIMARY RECOVERY FACTORS 38/

Recovery Range Average Recovery
Mechanism (in percent) (in percent)

Dissolved Gas Drive 5 - 3u 30
Gas Cap Drive 20 - 55 32
Water Drive 30 - 80 50
All Primary Drive 5 - 80 30

Both resources and reserve estimates are sensitive to economic.and technological
constraints (see Figure 2).' 39/

FIGURE 2:
PLETROLEIPI PESOURCES OF THE UNITED STATES

Demonstrated MDOCOVSWED
Measured Indicated Interred

...........

r% ...........
EAVES

..... .......... ......
............
..............
ir T
Jub JEN P.-i %.0 X77XFF %0 JEJ N-0

OF IncreasM degree of geob* &ssuranDee

Diagrammatic representation of petroleum resource elassification by the U.S. Geological Survey and
the U.S. Bureau of Mines (modified from McKelvey, 1973).

At any given level of technical capability a 'nd permitted selling price, some
quantity of petroleum known to exist will not be produced because production costs
would exceed the expected return. A good example is the Wilmington field in the
Los Angeles basin. The natural drive mechanisms of the Wilmington reservoirs have
been depleted, and extensive water flooding and other secondary recovery techniques
are used to maintain production. Wilmington-output is considered "lower tier"
production by the Federal Energy Administration, and the permitted sales price is
set by FEA at about $4.50/barrel. At this price, many of the wells in the field
will soon be shut-in and abandoned. Were FEA to permit Wilmington production to
be sold for more than $4.50/barrel, the producing lifetime of the field would be
extended, and ultimate recovery would increase. The practical effect of this
action would be to increase the proved reserves of the field.

181

Given these uncertainties, it is not surprising that reserve estimates
will vary., The American Association of Petroleum Geologists publishes an
annual summary of cumulative production and estimated reserves (which together con-
stitute estimated ultimate recovery) for all United States oil fields. One study
has compared the ultimate recovery estimates made at the time of field discovery
with the estimate made nine years after discovery, and found the latter to range
from 60% larger to 30% smaller than the original estimates. 40/ Another study
found that:

... estimates of the qdantity of oil in a reservoir, on average, con-
tinue to increase for at least 30 years and approach 5.8 times the
original estimate. D

Table 7 presents reserve estimates for California tidelands oil and gas fields,
as calculated by the State Lands Division effective January 1, 1976.

TABLE 7:
ESTIMATED CALIFORNIA TIDELANDS OIL AND GAS RESERVES 42/

Oil Reserves (MMB) Gas Reserves .(BCF)

Proved Inferred Proved Inferred
A. Ventura - Santa Barbara Basin

1. Existing State Leases 93.8 137.3 156.5 218.6

B. Los Angeles Basin

1. Existing State Leases 154.7 5.8 23.2 0.9
2. Granted Land Leases 314.4 15.0 66.0 3.2

TOTAL RESERVES 562.9 158.1 245.7 222.7

Table 8 presents reserve estimates for Santa Barbara Channel OCS discoveries
derived'from the individual fields and discovery estimates compiled by the OCS
Task Force.

TABLE 8:
SANTA BARBARA CHANNEL OIL AND GAS RESERVES

Oil Reserves (MMB) Gas Reserves (BCF)

Proved 264 224

Inferred 468 698

TOTAL 732 922

182

P R 0 D U C T 1 0 N F 0 R E C A S T S

Every oil field has a range of potential production rates, defined by reser-
voir properties, the size of the field, and other physical characteristics. Within
this range, actual production rates are often determined by economic or political
considerations.

When a field is first brought into production, oil flows into the production
wells on the strength of the reservoir's natural drive mechanism. This phase of
production, powered by the reservoir's own forces, is known as primary recovery.
Under primary recovery, an oil field's output rises within a few years to its
peak production rate, after which the reservoir's'natural drive mechanism loses
some of its original force. Almost immediately after peaking, production begins
to decline, ultimately reaching the economic limit.

To slow the decline rate, thereby increasing ultimate recovery from the field,
fluids can be injected into the reservoir to provide an artificial drive mechanism.
Production obtained through such artificial stimulation is known as secondary
.recovery. Water-flooding is a secondary, recovery technique commonly used in
California oil fields, as in the state's two-largest tidelands fields, Wilmington
and Huntington Beach. Advanced methods for enhancing production include the injec-
tion of chemicals into a reservoir to reduce the surface tension of the oil-in-
,place, or the injection of steam to lower the oil's viscosity. These so-called
tertiary recovery methods are expensive and not yet in wide use.

Natural gas production rates are especially difficult to predict. Under
current pricing reguIations, natural gas is less rewarding to produce than oil.
Operators often forego marketing produced natural gas in order to use it -- through
reinjection or gas-life operations to boost oil production. Moreover, many
platforms rely on natural gas as a power source. For these reasons, the amount of
gas sold from a platform is often much less than the amount of gas produced.

From the many choices.available for each field or discovery, the OCS Task
Force has constructed production forecasts for California tidelands and OCS oil
and gas fields, which, we hope, are both possible -- in view of the geologic
information available to us -- and plausible within the economic, technological,
and political context of offshore oil and gas operations. Table 9 presents our
production forecasts for the Santa Barbara Channel OCS. Individual field scenarios
are included in Chapter 10 (Development Scenarios).
TABLE 9:
CALIFORNIA TIDELANDS PRODUCTION SCENARIO, 1976 1993*

Year Oil (B/D) Gas (MCF/D)

1:976 156,900 45,300 1985 72,100 30,200
1977 146,900 41,500 1986 62,300 25,600
1978 137,500 42,500 1987 54,100 21,700
1979 139,400 62,300 1988 47,000 18,600
1989. 40,600 16,100
1980 128,100 56,200
1981 118,400 51,500 1990 35,500 13,600
1982 109,400 47,000 1991 29,800 10,300
1983 96,500 42,400 1992 25,300 8,600
1984 83,200 35,700 1993 22,100 7,500

*For notes and sources, see Appendix 2. TOTAL 549 MMB 210 BCF
183

TABLE 10:
SANTA BARBARA CHANNEL OCS PRODUCTION SCENARIOS, EXISTING DISCOVERIES*

CASE I CASE II CASE III CASE IV
Year Oil (B/D) Gas (MCF/D) Oil (B/D) Gas (MCF/D) Oil (B/D) Gas (MCF/D) Oil (B/D) Gas (MCF/D)

.1976 38,000 15,000 38,000 15,000 38,000 15,000 38,000 15,000
1977 34,000 13,000 34,000 13,000 34,000 13,000 34,000 13,000
1978 49,000 12,000 50,000 12,000 50,000 12,000 50,000 12,000
1979 54,000 12,000 62,000 12,000 62,000 12,000 62,000 12,000

1980 50,000 53,000 77,000 64,000 78,000 67,000 78,000 67,000
1981 46,000 51,000 74,000 67,000 86,000 84,000 86,000 84,000
1982 42,000 50,000 81,000 83,000 100,000 109,000 100,000 109,000
1983 40,000 49,000 84,000 94,000 120,000 145,000 120,000 145,000
1984 30,000 37,000 85,000 103,000 132,000 168,000 132,000 168,000

1985 23,000 28,000 84,000 103,000 137,000 182,000 147,000 197,000
1986 18,000 21,000 76,000 95,000. 144,000 197,000 183,000 256,000
co 1987 14,000 16,000 70,000 88,000 131,000 181,000 194,000 274,000
1988 10,000 12,000 65,000 84jOOO 126,000 174,000 186,000 264,000
1989 8,000 9,000 61,000 79,000 122,000 172,000 179,000 256,000
1990 6,000 7,000 47,000 80,000 110,000 154,000 173,000 249,000
1991 5,000 6,000 37,000 46,000 96,000 135,000 168,000 244,000
1992 3,000 4,000 26,000 35,000 82,000 119,000 156,000 229,000
1993 2,000 3,000 20,000 27,000 74,000 108,000 136,000 201,000
1994 2,000 3,000 16,000 20,000 59,000 86,000 121,000 179,000

1995 1,000 2,000 12,000 15,000 48,000 69,000 112,000 165,000
1996 1,000 2,000 10,000 12,000 39,000 56,000 88,000 130,000
1997 1,000 1,000 8,000 10,000 32,000 45,000 71,000 104,000
1998 6,000 8,000 25,000 36,000 57,000 84,000
1999 5,000 6,000 21,000 30,000 47,000 69,000

2000 4,000 4,000 18,000 26,000 37,000 54,000
174MMR- T_47NTF 413MMB 429BCF Tl _7MMB 874BCF MMB 1307BCF

*1997 and 2000 are arbitrary cut-off dates for these scenarios and are not intended to suggest that Channel OCS
production will cease at those times. Figures rounded to nearest thousand. For Case assumptions, see Notes,
Appendix 2.

FOOTNOTES

1. Numerous documents@present summaries of tidelands oil and gas production
as well as pertinent statistics. Especially important are: California Division
of Oil and Gas, California Oil and Gas Fields, Volume 2, South, Central, Coastal
and Offshore California, published annually; California State Lands Division,.
Hydrocarbon Potential of California Offshore Lands and San.Pablo Bay, Auqust 1976;
and, Conservation Committee of California Oil Produ_c_e_r_s_,_An_nual Review of California
Oil and Gas Production, 1975.

2. The discovery was made on Shell's Lease 301 (Tract 262) in San Pedro Bay.

3. Much of this material is taken from Western Oil and Gas Association,
Environmental Assessment Study 'Proposed Sale of Federal Oil and.Gas Leases,
Southern CYl-ifornia Outer Continental Shelf, Subsection II-A, "Petroleum Exploration,"
October 1974. See also U.S. Department of the Interior, U.S. Geological Survey
Final Environmental Statement-1, Oil and Gas Development in the Santa Barbara -
Channel Outer Continental Shelf Off California, March 1976, Appendices 1-2, 1-3,
and pp. 1-205 ff.

4. U.S. Department of the Interior, Geological Survey Circular 730, Geologic
Appraisal of the Petroleum Potential of Offshore Southern California: The Border-
land Compared.to Onshore Coastal Basins, 1976.

5. Ibid., p. 13.

6. U.S. Department of the Interior, Geological Survey, Open File Report 76-232,
Geological and Operational Summary, Southern California Deep Stratigraphic Test
OCS-CAL 75-70 No. 1, Cortes Bank Area Offshore Southern California,, 1976.

7. U.S. Department of the Interior, Geological Survey Circular 730, 2R. cit.,
P. 1.

8. U.S. Department of the Interior, Geological Survey Professional Paper 679,
Geology, Petroleum Development, and Seismicity of the Santa Barbara Channel Region,
California., 1969, pp. 5-8.

9. See summary on Santa Barbara Channel oil and gas operations in Section.I
of U.S. Department of the Interior, Geological S,urvey Final Environmental Statement,
op. cit., March 1976.

10. Much of this material on the history of California offshore production is
taken from The Offshore Petroleum Resource,.Resources Agency of California, 1971,
especially @`p. 6-7-76.

11. See also Outer Continental Shelf Oil and Gas Leasing Off Southern California:
Analysis of Issues, Committee,of Commerce, U.S. Senate, November 1974.

12. See also Section 1 of U.S. Department of the Interior Geological Survey
Final Environmental Statement, op. cit., March 1976.-

13. For useful summary of events surrounding-the blowout, see Resources Agency
of California, op. cit., pp. 134-139.

14. Press release, January 6, 1977, Office of the Secretary of the Interior.

185

15. See footnote 2.

16. Adapted from Reserves of Crude Oil, Natural Gas Liquids, and Natural Gas
in the United States and Canada as of December 31, 1975, American Gas Association,
American Petroleum Institute, and Canadian Petroleum Association, 30, May 1976,
pp. 13-20; Hydrocarbon Potential of California Offshore Lands and San Pablo Bay,
California State Lands Division, August 1976, p. 27; and, GeoT-ogical Estimates of
Undiscovered Recoverable Oil and Gas Resources in the United States, Geological
Survey Circular 725, U.S. Department of the Interior, 1975, pp. 8, 9.

17. USGS estimates contained in Final Environmental Statement 1, Proposed 1975
Outer Continental Shelf Oil and Gas General Lease Sale Offshore Southern California
(O.C.S. Sale No. 35)'Bureau of Land Management, U.S. Department of the Tn-terior,
August 1975-Tnd -in U.S. Geological Survey Final Environmental Statement 1, op. cit.,
March 1976. Western Oil and Gas Association estimates presented in Western Oil -
and Gas Association, op. cit., October 1974, and in the open letter of Harry Morrison,
Western Oil and Gas Association, August 1, 1975.
18. A good discussion of resource estimate methodologies is contained in
Geological Estimates of Undiscovered Recoverable Oil and Gas Resources in the
United States, Geological Survey Circular 725, U.S. Department of the Interior,
1975.

19. Oil and Gas Journal, September 22, 1.975, p. 66.

.20. The actual USGS estimates were higher, because the Santa Monica Bay area
was included in the USGS overall resource estimate. However, the Santa Monica Bay
tracts were withdrawn before Lease Sale #35 was held. The individual area resource
estimates (San Pedro Bay, Santa Rosa Cortes North, Santa Rosa Cortes South, and
Santa Barbara-Santa Catalina) are unchanged, but we have modified the overall USGS
Lease Sale #35 resource estimate to reflect the deletion of Santa Monica Bay tracts.
See Bureau of Land Management Final Environmental Statement 1, op. cit., U.S.
.Department of the Interior, August 1975.

21. Western Oil and Gas Association, oD. cit., Executive Summary, p. iii.

22. Parker's paper, Petroleum Potential of Southern California Offshore, is
presented in the American Association of Petroleum GeoloqiStS' Memoir r5-,Future
Petroleum Provinces of the United States--Their Geology and Potential, 1, p. 178-191.
23. Western Oil and Gas Association, op. cit., Executive Summary, p. 17.

24. Harry Morrison, Western Oil and Gas Association, op. cit.

25. For example,.37 local and regional governments in southern California
joined in liti.gation to halt Lease Sale No. 35.

26. U.S. Department of the Interior, Bureau of Land Management, op. cit., 2,
p. 592, Table VIII.

27. U.S. Department of the Interior, Geological Survey, Final Environmental
Statement 1, M. cit., p. 1-183, Table 1-4.

28. This statement was made to the OCS Task Force by "Deep Strat," a USGS
official who asked to remain anonymous. The table in question does not appear in
the Draft Environmental Impact Statement-,but only in the Final EIS.

186

29. California State Lands Division, Resource Appraisal ' Offshore Southern
California OCS Sale #35, for Governor's Office, Office of Planning and Research,
1975, 3 (Resource A sment), p. 3-1.

30. Harry Morrison, Western Oil and Gas Association, op. cit.
31. The direct USGS quote, and the Parker quote, are from U.S. Department of
the Interior, Geological Survey Circular 730, op. cit., pp. 30, 31.

32. Oil and Gas Journal, September 22, 1975, p. 66.

33. This table uses the USGS high range estimates presented in the Final
Environmental Statement, U.S..Department of the Interior, Bureau of Land Management
1, op. cit., p. 1, and the USGS low range estimates presented in U.S. Geological
Survey Ti-nal Environmental Statement 1, op. cit., March 1976, p. 1-183.-
34. U.S. Department of the Interior, Geological Survey, Final Environmental
Statement, op. cit., p. 167.

35. Ibid.

36. See footnote 14.

37. Much of the material in this section is taken from Initial Report on Oil
and Gas Resources, Reserves, and Productive Capacities, Fede-ral Energy Administration,
Office of Policy and Analysis and Office of Energy Resource Development, June 1975,
pp. 21-38.

38. Ibid., p. 33.

39. U.S. Department of the Interior, Geological Survey Circular 725, 2P. cit.,
p. 8.

40. E. L. Dillon and L. H. Van Dyke, Exploratory Drilling in 1965, American
Association of Petroleum Geologists' Bulletin, 1966, 50, pp. 1114-1138; quoted in
H. W. Menard, Exploration History and Random Drilling Models, in press.

41. M. Hubbert, Dearee of Advancement of Petroleum Exploration in United
State . American Association of Petrolum Geologists Bulletin, 51, pp. 2207-2227;
also quoted in Menard, op. cit.

42. California State Lands Division, op. cit., August 1976.

187

CHAPTER 15

AIR QUALITY:
OMISSIONS AND EMISSIONS

This Chapter is divided into two parts. Part One reviews the regulation
of air quality impacts on the OCS. Part Two contains a highly technical review
of air quality impacts of OCS development on the Santa Barbara Channel.

S U M M A R Y

The following is a concise outline of the major conclusions and recommenda-
tions of this study:

1. In general, oil industry-related pollutant concentrations are directly
dependent upon production: the more oil produced, the higher the pol-
lutant level.

2. Tanker loading has a significant effect on local and regional ozone
concentrations. In terms of ozone formation, pipelines are preferable
to tanker transport.

3. If tankers are used for transporting local crude, several measures shou,ld
be used in order to reduce the air quality impact: slow loading, partial
filling, and coordinated scheduling seem most useful.
4. In order to ensure compliance with one-hour state standards for.S02 and
H2S, treatment and separation-facilities should be limited in size.
Several smaller facilities are preferable to one very large one.

5. Analysis of various production/processing/transport scenarios for Exxon's
Hondo platform and selected facilities indicates that a marine terminal
could significantly affect local ozone concentrations, that an offshore
processing facility would affect Goleta/Santa Barbara air quality more
significantly than would a Las Flores Canyon site, and that near-plant
S02 @nd H2S concentrations at Las Flores might approach or exceed air
quality standards unless emission controls or plant size restrictions
were adopted.

189

6. The available data base leaves much to be desired. Notable deficiencies
were found in the meteorological data set (particularly wind and upper
air sounding data) and in offshore oil industry, emissions information.
In order to allow more definitive impact statements in the future, it is
suggested that these deficiencies be corrected as soon as possible.

PART ONE

The regulatory structure for maintaining air quality in California is resolved
into three levels of federal, state, and local jurisdiction. The extent of
that jurisdiction, however, and the applicability of existing permit and review
procedures to guarantee equivalent trade-offs or to control emissions resulting
from OCS development is questionable. Offshore regulations applicable to OCS ac-
tivities are needed to complement and strengthen state and local efforts to assure
the attainment and maintenance of air quality standards onshore. Amendments to the
Clean Air Act and the OCS Lands Act appear to offer an expeditious solution to the
many legal uncertainties surrounding air quality jurisdiction of the OCS.

PART TWO

Using available meteorological and emissions information, potential air
quality.impacts of petroleum-industry activity on the Santa Barbara Channel were
estimated. The ARTSIM* photochemical/diffusion,model was used for assessing reac-
tive pollutant buildup, while primary pollutant concentrations were modeled using
ERT's Point Source Diffusion Model (PSDM). ARTSIM modeling included simulation of
carryover effects and point source emission impacts (platforms, processing facili-
ties, and marine terminals). In addition, photochemical impacts of natural oil
seeps and accidental offshore spills were modeled.

Results of the simulations indicate'that tanker loading could significantly
increase local ozone concentrations, and that a 6,000 barrel spill in the Channel
could, under unfavorable meteorological conditions, lead to high ozone buildup as
well. Sulfur dioxide and hydrogen sulfide concentrations approaching or exceeding
California one-hour standards were predicted in the vicinity of large processing
facilities.

Suggested mitigating measures include area-wide tanker use strategies, partial
tanker filling, limitation of size of processing facilities, and use of effective
vapor control systems. Additional suggestions include broadening the l.ocal
meteorological, air quality, and emissions data base.

ARTSIM stands for Atmospheric Reaction and Transport Simulation.

.190

PART ONE: AIR QUALITY REGULATIONS
AND RESEARCH PRIORITIES

AIR QUALITY REGULATIONS

It is widely acknowledged that some degree of air pollution will result from
oil and gas production activities on California's Outer Continental Shelf (OCS) *
In areas with serious air pollution problems, such as the Los Angeles basin, any
new source of pollutants is critical, no matter how small. This section examines
the regulatory structures for maintaining air quality in California, the agencies
within that structure, and the laws by which they operate. Special attention is
given to those problems and planning strategies which may affect oil and gas pro-
duction activities resulting from federal OCS leases.

F E D E R A L A U T H 0 R I T Y

Federal involvement in air quality regulation began with passage of the Air
Pollution Control Act of 1955. Subsequent decisions culminated in the Clean Air
Act (CAA) Amendments of 1970 -- the heart of the current federal,-state, and local
regulatory system. The federal role established by the CAA is to identify pol-
lutants, establish standards, and oversee state and local enforcement. Federal
guidelines establish a minimum threshold of regulation, above which states may
impose tougher regulatory requirements but below which they may not fall. Sections
108 through 111 of the CAA establish the mechanism for regulating OCS activities
affecting air quality.

Section 109 requires the EPA Administrator to establish national ambient air
quality standards (NAAQS) for identified pol-lutants. The legal mechanism to
achieve ambient standards i's the State Implementation Plan (SI.P) mandated by Sec-
.tion 110 of the Act. Section 111 requires EPA to.identify causes of stationary
sources which may "contribute significantly" to air pollution and establish federal
performance standards that reflect the degree of emission limitation which can be
achieved by the best available control technology. EPA can theoretically control
emissions from any industrial processor facility, but only one of the standards it
has promulgated applies to OCS-related sources. Thus most OCS facilities are not
presently regulated.

NEW SOURCE PERFORMANCE STANDARDS FOR OCS-RELATED OPERATIONS

The single new source performance standards (NSPS) established for OCS-related
sources sets hydrocarbon limits from petroleum storage tanks of 40,000-barrel
capacity or larger. l/ The NSPS requirement that storage tanks have a floating
roof and a vapor recovery system, or its equivalent, is well within the limits of
technological and economic feasibility, and has not created a substantial problem
for OCS-related facilities. There are currently no new source performance stan-
dards for platforms, processing plants, gas plants, pipelines, or marine terminals,
although any of these located within state jurisdiction must obtain local permits
for construction and operation. The EPA does not expect its NSPS for other oil
and gas-related facilities, such as platforms and processing plants, to be
articulated before late 1978.

The EPA has delegated enforcement authority for NSPS to local air pollution
control agencies. To promote uniform interpretation of the regulations, EPA

191

guidelines identify the administrative procedures local agencies should adopt for
implementation and enforcement of the standards.

S T A T E A U T H 0 R I T Y

The apparent complexity of air quality regulation stems in part from over-
lapping federal, state, and local authority, The national program established
by the Clean Air Act requires EPA to establish minimum national standards and
leaves implementation to state and local governments. The EPA retains authority
to review state programs and substitute its own in whole or in part when it deems
the state effort inadequate. The state program mirrors that structure. The Air
Resources Board (ARB) is the EPA analogue. It sets standards and delegates their
implementation to local Air Pollution Control Districts, while retaining the
authority to impose a state program where necessary. Similarly, just as federal
standards establish a minimum floor which the state may exceed, state standards
establish only the minimum requirements for local programs.

LOCAL CONTROLS

Local involvement in air pollution control in California predates both state
and federal action. The severity of air pollution in Los Angeles was recognized
in the mid-1940s and resulted in the passage of the County Act of 1947. This
allowed counties in California to form air pollution control districts (APCDs).
APCDs have the sole responsibility for controlling emissions from stationary
sources located within their jurisdiction. They are authorized to establish
regulations to conduct a permit/review procedure before pollutant-emitting indus-
tries or operations can be constructed or modified. Two general classes of permits
are required by the APCD:

Basic Equipment: This class includes any article, machine, equipment, or
contrivance which emits, or has the potential to emit, air contaminants; and,

Air Pollution Control Equipment: This class includes any article, machine,
equipment, or contrivance that eliminates, reduces, or controls the issuance of
air contaminants.

A corporation, company, individual owner, or governmental agency seeking to
construct or modify a facility which uses the equipment described above must apply
for a permit. Before granting the authority to construct or a permit to operate,
each application must be accompanied by complete data, plans, descriptions, speci-
fications, and drawings to show how the proposed equipment is designed, the manner
in which it will be operated, and how emissions will be controlled. 2/ The
detailed process of environmental review conducted by the APCD is sh_o@n in Figure 1.

AIR RESOURCES BOARD.

The California State Air Resourc es Board (ARB) was created in 1967 by the
Mulford-Carrell Air Resources Act in response to a federal legislative initia-
tive requiring the establishment of a single state agency for air pollution. The
ARB has five principal responsibilities:

1. to divide the state into air basins (see Figure 2);

2. to set ambient air quality standards (where federal and state standards
differ, the more stringent standard prevails);

192

FIGURE I
AIR POLLUTION CONTROL DISTRICT GENERAL ENVIRONMENTAL REVIEW PROCESS FLOW CHART
Application Received For %
Authority To Permit To
Construct Operate
4
Determine if project is:
1. Ministerial NO ENVIRONMENTAL REVIEW
2. Categorically exempt required by APCD. Consult
3. Not categorically other responsible agencies
exempt as necessary before proces-
I sing application
determination of -Initial study by I
lead department applicant Process application in
I accordance with permit
Determine if the project standards of APCD
will have a significant regulations.
effect on the environ-
ment I
no significant effect possible significant
I effect
APCD prepares negative declaration. -)Draft EIR by applicant
Consult with other responsible
agencies as necessary. Appeal Decision

Post with County Clerk for specified File notice of completion and
comment period (10-30 days) legal post with County Clerk. Distribute
notice in newspaper. for comments within 30-day comment
Comments received period.
41 Consult with public agencies having
no significant possible significant jurisdiction by law.
effect effect I
APCO prepares final EIR.
lead department
approves EIR (satisfactory)

Applications to APCD for A/C Back to Hearing
41 Applicant Board
more information Review for Compliance with emissions
optional APCO( standards unacceptable

Acceptable
New Source Review---:@-if less than 15 lbs./hr. or I lbs./day
If 15 lbs/hr. or 150 lbs/day
No impact analysis
or greater required
more information -,-Impact Analysis Awar@A/C
optional APCO
Public Review 30 days
1@
Public Comment

Comment Review Hearing Board Rework Prop. idea
more information4@:-Decision by [email protected]
optional APCO 1 4
Award A/C Conditional
Permit

Source: "Compilation of Air Pollution Control Regulations and Sta ndards," Energy Resources Conservation and Develop-
ment Commission, Facility Siting Division, June 8, 1976, p. 23.

193

FIGURE 2

NO RT H EiA S T

.......... --------------------------
PCATEAU
i
CALIFORNIA AIR BASINS

------ - ---

NORTH --------- .. .... .......
COAST
_,A.@ENTQ SCALE IN MILES
VAL@TY AKE
LAK ------ 44OUNT TAHOE 0 100
co

SAN
FRANCISCO
BAY AREA ------- --- ----

--- GREAT
SAN JOA401'N
VALt,'EY
NOR TH BASIN
CENTRAL
COAST VALLEYS

- --- - ---------- - - - ------- --- ----- - -i

SOUTHEAST
SOUTH
CENTRAL
COAST

DESERT

...........

SOUTH

..........
COAST I

SAN
DIEGO

194

3. to promulgate rules and regulations largely through the State Imple-
mentation Plan;

4. to establish emission standards for all.stationary and non-vehicular
sources within each basin; and,

5. to develop test procedures to measure compliance.with its stationary
emissions standards and those of APCDs. 3@

The State Implementation Plan (SIP) is specifically mandated by Section 110
of the Clean Air Act. Each state's SIP is to provide for the attainment of both
primary and*secondary air quality standards. EPA sets primary standards at levels
necessary to protect public health and less rigorous secondary standards at levels
nece@ssary to protect the public welfare from known or anticipated adverse effects
of regulated pollutants.

The simplest form of air pollution control regulation is merely an Ilemission
limitation" which restrains the amount of any pollutant that may be discharged
from a particular source. The attainment of ambient standards, however, requires.
a more sophisticated control system since the quality of ambient air at any point
depends not only upon the total amount of emissions, but upon the location of
their sources as well. The CAA.recocinizes this fact, requiring implementation
plans to contain:

emission limitations ... and such other measures as may be
necessar@ to insure attainment and Fa-intenance.of such
(ambient) standard, including, but not limited,to, land
use and transportation controls. 4/ .[Emphasis added.]

The EPA determined in 1971 that one of the "other measures necessary" was pre-
construction review of proposed new sources with authority to prohibit the
construction of those which would interfere with the attainment or,maintenance
of ambient standards. 5/ Compliance w@ith these new source review (NSR) pro-
cedures and standards poses a potentially difficult hurdle for OCS-related
sources.

The other general CAA requirements for a SIP are that it must:

1. provide for the attainment of primary health-related standards wtthin
three years and secondary standards within a "reasonable time"-.

2. establish emission limitations, schedules, and timetab-les for compliance;

3. provide for the review of.-newor,modified sources of emissions to assure
compliance with NSPS established by'EPA; and,

4. ass-ure that emissions of pollutants from one air quality-basin will not
interfere with the attainment of standards in another basin.- 6/

The state's.legal authority to enforce the above requi,rements-must be built into
the SIP. EPA regulations also require the SIP to include-authortty-forthe state
to override local APCD standards and-to assume enforcement-powers if the APCDs
cannot ach.ieve and maintain air quality'-standards.

The EPA reviews all SIPs and will substitute its own guidel.ines and programs
for those that are judged inadequate to meet national ambient-air quality-standards...

14-76658 195

The EPA may also override state authority in instances where the state fails to
enforce its SIP. If the EPA fails to act against violators of national emission
standards or state and federal compliance orders, then private citizens may file
suit against the EPA for nonperformance of its statutory duties.

California's implementation plan is a compilation of the rules, regulations,
and strategies adopted by the local APCDs. The ARB submits to the EPA quarterly
the revisions of the SIP control strategies and all APCD rules and regulations.
Currently, the ARB is rewriting the existing SIP. This revised version will con-
tain both existing and proposed control strategies, updated projections of future
emissions and air quality, and,individual plans for the 14 air basins in California.
The new SIP should be ready for submission to the EPA by early 1977. 7/

California's original SIP was rejected because, among other reasons, EPA
determined that NSR rules were inadequate. Most of the districts had adopted
rules which called for intensive review only of those new sources emitting
more than 100 tons/year of a regulated pollutant, and which allowed one integrated
facility, such as a refinery, to be broken into constituent parts for review
purposes, thus avoiding the intent of the rule. EPA did, however, accept the NSR
rules of a few districts and approved them as part of the SIP, thus conferring on
the rules the status of enforceable federal regulations.

Where EPA rejected proposed dist'rict rules, the agency promulgated its own
NSR regulations. This is the case in Santa Barbara, Ventura, Los Angeles, Orange,
and San Diego counties. In these counties, a double permit system is in effect.
The APCD enforces its NSR rule, and EPA enforces the NSR rule it has adopted for
the district. When modified NSR rules are submitted to EPA as part of the SIP and
found acceptable, the agency will terminate its separate permit system and adopt
the District's rules as federal regulations, leaving enforcement to the District.

In order to re-establish state and local control over new source permits,
the ARB has developed a second generation of NSR rules and is urging their adoption
by the APCDs. New or modified rules submitted to the ARB will be forwarded to EPA
as part of the SIP, if they meet ARB guidelines. If the ARB determines that an
APCD rule proposed for inclusion in the SIP is inadequate, it is sent back to the
APCD with suggested revisions. If an APCD fails to revise its rules, or submits
revised rules which are still inadequate, the ARB prescribes NSR rules for the
.district that cannot be amended except with approval of the ARB Executive Office.
This,is what happened.to the Southern California Air Pollution Control District
(SCAPCD). The ARB adopted NSR rules for the District on October 8, 1976. While
these rules are not presently applicable outside the District, the ARB intends them
as.gui.delines for APCDs seeking to have NSR rules-included in the SIP for approval
by EPA so that local control can be re-established over the permitting and regula-
tory process.

The ARB-suggested NSR rules require each district's air pollution control
officer (APCO) to review proposed stationary sources or modifications to existing
if it is suspected the resulting emissions will exceed certain rates. The
sources 1
emission "cutoff" rates, beyond which review is required, are 15 lb/hr or 150 lb/
day for any pollutant for which there is a state or national standard, except
carbon monoxide. These rates also apply to any precursor pollutant (such as
reactive hydrocarbons) that contributes to the formation of a pollutant for which
.standards exist. The cutoff rates for carbon monoxide are 150 lb/hr or 1500 lb/day.

The APCO must deny a permit for construction of-any modified source if its
emissions will cause or contribute to continued violation of state or national.

196

ambient air standards within the district, regardless of whether the source
is meeting other applicable standards or not.

EMISSION TRADE-OFFS. A facility'may be constructed in an area where stan-
dards are currently exceeded, or where its emissions will prevent the attainment
or maintenance of standards only if an equivalent reduction in emissions can be
achieved from facilities already within the area. These emission trade-offs
are allowed only at the discretion of agencies administering the NSR program.
In California, presently, this would be the EPA and/or those APCDs that operate
with approved NSR regulations. However, any permit to construct and operate
granted by an APCD is conditional for 90 days, pending ARB review.

EXEMPTIONS. The Exemptions allowed from NSR vary according to each APCD's
rules. Pollution-control equipment is generally exempted, as is'public service
equipment. Exemptions are granted to'a source that would result in a demonstrable
basin-wide benefit. Modifications to accommodate changes in fuel sources -- nec-
essary because of diminishing natural gas supply -- are exempt, with certain
qualifications.

There is some room for interpretation in the NSR exemptions allowing for a
new or modified source to locate within an area if it has been determined that:

1. unique and innovative control technology will be used, resulting in
significantly lower emission rates from the source than would have
occurred using known best available control technology (BACT); and,

2. the development of control technology will be significantly advanced,
benefitting both environmental and public health concerns.

A source providing demonstrable basin-wide benefit, for example, might
.include a desulfurization facility like the one built in El Segundo. Under
normal new source review, such a facility would be denied its permit to construct;
but if denied, then the area would be without a source of low-sulfur fuel oil. It
may be judged more beneficial to have the low-sulfur fuel oil available and to
tolerate the added pollutants from the facility itself.

No APCD may grant an exemption without approval of both the ARB and the EPA.
NSR rules that fail to provide for the ARB and/or EPA to override the granting
of exemptions are unacceptable to the ARB and will not be submitted to the EPA.

N E W S 0 U R C E R E V I E W A N D 0 C S

NSR is a potentially significant hurdle for OCS-related facilities in the
South Coast area. The region's present inability to comply with oxidant stan-
dards requires that permits for new reactive hydrocarbon sources be denied
unless the facility falls within an exemption, or the applicant can provide
offsetting emission reductions from other sources in the area which are accept-
able as trade-offs to the EPA, ARB, and the local APCD.

New source review rules are of recent origin and have not, as yet, been
applied to OCS-related facilities. 'Their potential effect, however, extends to
all facilities within state jurisdiction (e.g., oil and gas processing plants,
storage tanks, pumping stations, and marine terminals), and possibly to some
platforms and other OCS facilities beyond the state's three-mile limit as well.
Tanker loading operations appear to be the most significant source of reactive
hydrocarbon emission from OCS-related facilities.

197

After a tanker is unloaded, hydrocarbons vaporize from the tank residue and
form a rich blanket in the cargo hold which must be displaced into the atmosphere
as the tank compartments are filled with crude oil. These emissions may be
reduced in volume and intensity to some degree by varying the loading rate and
level to which cargo compartments are filled, but there is no demonstrated tech-
nology for vapor recovery. Since the tanker, not the loading terminal itself, is
the point of origin for reactive hydrocarbon emissions,there was some question
whether the rules regarding stationary sources could be applied. The'ARB faced
this issue with SOHIO's, permit application for a loading terminal in Long Beach
and amended the proposed South Coast NSR rule to charge tanker emissions against
the marine terminal:

.where all or part of a stationary source is a facility used to load
@a*rgo onto or unload cargo from cargo carriers other than motor vehi-
cles, the Air Pollution Control Officer shall consider such carriers
to be parts of the stationary source .... Emissions from such carriers
shall include those that result from,the operations of the carriers'
engines; the purging or other method of venting vapors; and from the
loading, unloading, storage, processing, and transfer of cargo. 8/

Historically, most of the OCS and tidelands oil production from the Santa
Barbara Channel has been transported to the Los Angeles area, where over 54% of
the state's refining capacity is located. Three small (8"-10") pipelines link
the Santa Barbara-Ventura area with refineries. The pipelines, however, already
operate at near capacity carrying onshore production. Most local offshore pro-
duction is loaded into tankers. Unless a pipeline is constructed from this pro-
ducing center to refineries, expanded OCS production from existing leases will
have to be transported by tanker and is expected to have a significant adverse
effect on local air quality. An air quality analysis for the Santa Barbara
County Regional Transportation Plan states bluntly:

... should tankships continue to be the only mode of crude oil trans
port, the South Coast would not be expected to meet the 8 pphm federal
oxidant standard by 1995. If all tankship emissions are eliminated
through vapor recovery or conversion to pipeline transport, the
oxidant standard would be achieved by 1984. 9/

JURISDICTION OVER OCS FACILITIES

Offshore facilities beyond the State's three-mile jurisdictional limit enjoy
a de facto Clean Air Act exemption. No such facilities have yet been subjected
to@_the reviews, permit controls and emission standards applied by federal, state,
and local agencies onshore.

INTERIOR DEPARTMENT. Under court interpretations of the OCS Lands Act, the
Interior Department has broad authority for "conservation of the natural resources
of the outer continental shelf...." 10/ This phrase was interpreted in Gulf Oil
Corporation v. Morton to encompass aT_l the natural resources of the shelf, not
merely the mineral resources. ll/ Although a case has never been decided exactly
on this point, clean air is pr-obably among the natural resources which the Secretary
may act to conserve.

OCS regulations take a broad view of the Interior Department's jurisdiction
stating:

... all operations conducted on a lease by or on behalf of a lessee are

198

subject to the regulations in this part, and are under the jurisdiction
of the Supervisor... 121

Subsequent regulations, however, are directed at water pollution and oil spills
(30 C.F.R. 1250.43) and are devoid of any reference to air pollution. Despite
the Department's broad jurisdiction, this study has discovered no instance in
which its authority has been exercized to affect either operating procedures or
equipment specifically to reduce,air pollution effects of OCS operations. Air
quality has been virtually ignored in the Interior Department's regulation of OCS
activities.

ENVIRONMENTAL PROTECTION AGENCY. The extent of EPA's jurisdiction is
unclear, since the Agency has not yet attempted to exercise its regulatory auth-
ority in circumstances which would precipitate litigation and a judicial inter-
pretation of the Clean Air Act on this issue.

The OCS Lands Act.provides:

The Constitution and laws and civil and political jurisdiction of the
United States are extended to the subsoil and seabed of the Outer
Continental Shelf and to all artificial islands and fixed structures
which may be erected thereon for the purpose of exploring for,
developing, removing, and transporting resources therefrom, to the
same extent as if the Outer Continental Shelf were an area of exclu-
sive federal jurisdiction located within a state. 13/

This provision can be read to make the New Source Performance Standards
developed by EPA under Section.111 of the CAA applicable to the Outer Continental
Shelf. 14/ It can also be read to extend the application of other federal air
pollution regulations to the OCS.

Section 110 of the CAA,empowers EPA, in the event of an inadequate state
plan (SIP), to adopt added regulations "for a state." Such regulations have
been held to be federal law, and as such, would presumably be applicable on
the OCS. 15/ Whether EPA has the authority to adopt an SIP which applies beyond the
geographi-c-boundaries of a state, however, is disputed.

The CAA requires each state to adopt "a plan which provides for implementa-
tion, maintenance, and enforcement of (primary standards) ... within such state"
[emphasis added]. 16/ Proponents favoring a narrow construction of state and
federal jurisdicti5-n argue that the terms "within such state" act to limit the
area for which regulations may be developed. They argue that a state's authority
is limited to areas within the state and since EPA's power is derivative, that
EPA's authority is thus necessarily confined to-the area where the state is to
prepare an implementation plan. 17/ That assertion, however, is not self-
evident. It appears reasonable to interpret.the terms not as limiting the area
for which regulations may be adopted, but as merely establishing a minimum stan-
dard against which proposed regulations will be tested. In this case, their
effect is not to prevent EPA from adopting regulations which would apply beyond
the boundaries of a state -- on the OCS for instance -- but to require that as a
minimum any plan provide for attainment of standards within the state.

EPA has not formally adopted a position interpreting the Clean Air Act's
applicability to OCS activities and identifying the extent of the agency's
authority. At the time of this writing, EPA Region IX (West Coast) was preparing
to request a formal opinion of EPA's Office of General Counsel establishing

199.

guidelines for the agency's action on OCS activities under the CAA. 18/

Apart from the CAA, there is one additional statutory base upon which EPA
may be able to assert some controls over OCS air pollution. The Federal Water
Pollution Control Act gives EPA permitting authority over both navigable waters
within the state's 3 mile boundary and out to the 12 mile boundary of the conti-
guous zone. Section 201(a) generally prohibits the discharge of "any pollutant"
without an NPDES permit. OCS facilities within the contiguous zone usually
require NPDES permits for disposal of drill cuttings, brines, or treated sewage.
These permits may provide a means for regulating some OCS air emissions.

EPA has recently c 'Q'ncluded that non-water-quality effects, such as air
emissions,*otherwise beyond the jurisdiction of the agency may be considered in
reviewing'new source discharge permits and may provide the basis for denying or
conditioning such permits. The General Counsel's opinion states:

NEPA requires EPA to consider all of the environmental impacts of
its actions in connection with the issuance of new source discharge
permits and the requirement to consider environmental impacts
carries with it the power to deny or condition permits based on
environmental reasons (apart from those approved in the Federal
Water Pollution Control Act) alone. 19/

This opinion appears to lay the groundwork for EPA to assert jurisdiction
over air emissions of OCS facilities within the 12-mile-contiguous zone. The
agency has not yet tested this authority on any OCS facility. If the authority
is ultimately upheld, it will provide an avenue for establishing EPA jurisdiction
over some OCS facilities. Several questions remain, however: (1) what standards
and controls will be applied to these "extra-jurisdictional" facilities? (2) what
controls, if any, can be applied to facilities outside the 12-mile contiguous zone?
and, (3) whether operators will modify operations to escape the necessity for
NPDES permits in order to avoid potentially costly air quality regulations.

STATE AND LOCAL JURISDICTION. The OCS Lands Act provides for the extension
of some state laws to OCS facilities in the following terms:

To the extent that they are applicable and not inconsistent with this
subchapter or with other federal laws and regulations of the Secretary
now in effect or hereafter adoptedi the civil and criminal laws of
each adjacent state ... are declared to be the law of the United States
for that portion of the subsoil and seabed of the Outer Continental
Shelf, and artificial islands and fixed structures erected thereon,
... [emphasis added] 201

For state and local regulatory requirements governing air pollution to be
applied on the OCS, three potentially fatal legal questions must be answered
satisfactorily: (1) Are they consistent with the OCS Lands Act? (2) Are they
consistent with regulations in effect or subsequently promulgated? and, (3) In
the case of APCD regulation, are they "state law" for this purpose?

Opponents of state and local regulation beyond three miles argue that the
Act contemplates five-year lease terms which convey the right to "produce" oil
and gas. Any regulation which established a pre-condition interferes with that
right to produce and is thus inconsistent with the OCS Lands Act. 21/
Proponents of extending state and local controls argue that the Ad-rs "right to
produce" was not intended to be absolute. It was intended that the right be

200

reasonably conditioned by civil and criminal laws of the adjacent state. Subse-
quent federal legislation, including the Clean Air Act and NEPA, demonstrate a
strong commitment to environmental protection, including air quality. State laws
in pursuit of these goals -- which do not prohibit production from OCS leases,
but merely subject it to reasonable conditions -- are not necessarily inconsistent
with the OCS Lands Act.

The requirement that state law not be inconsistent with the Secretary of
Interior's regulations presents perhaps the most difficult legal problem for pro@
ponents of asserting state jurisdiction. Insofar as the Secretary's regulations
are silent on air pollution, the argument made above that reasonable state
regulations may be applied, still obtains. If, however, the Secretary adopts
regulations specifically controlling air pollution from OCS facilities,.state
regulations that had the effect of prohibiting a facility the Secretary allowed,
would undoubtedly be hel-d "inconsistent" with the Secretary's regulations and thus
invalid.

In the.case of local regulations, there is one additional legal hurdle which
must be surmounted before they can be applied to OCS facilities. Exxon raised
this issue in a memorandum to EPA which contends, in part, that the OCS Lands
Act incorporates only statewide law -- not local regulations. _221 In
support of this position, Exxon argues that the OCS Lands Act r-epeatedly distin-
guished between states and their political subdivisions and even'made provision
for projecting state lines seaward to establish which state would have i.ts civil
and criminal laws apply to OCS structures, while at the same time it made no
similar provision for extending the lines of political subdivisions seaward.

Each of the options for establishing air emission controls presents slightly
different problems. With Interior Department regulation or EPA regulation under
the FWPCA, a major question is what standards will be applied. Neither option
necessarily requires regulations to be consistent with those established for simi-
lar facilities onshore. While regulatory authority may be found in these cases,
the controls and substantive standards will not necessarily be those of the Clean
Air Act, case law interpreting the@CAA will not be applicable, and citizen suit
provisions of the CAA will not apply.

Efforts to impose state or local controls directly under th e OCS Lands Act,
or to include them in an SIP, or have EPA impose them in SIP under the Clean Air
Act are all subject to legal attack on issues which may take years to
resolve in court.

Amendments to the Clean.Air Act and the OCS Lands Act, actively under consi.-
deration in the 95th Congress, appear.to offer a clean way to resolve some of
these legal uncertainties and assure that offshore regulation will complement and
strengthen state and local efforts to assure the-attainment and maintenance of-
air quality standards onshore.

A I R P 0 L L U T 1 0 N C 0 N T R 0 L C 0 U N C I L S

In air basins comprised of more than one APCD, an air pollution control
council is formed with responsibility to develop a basin plan, including the rules
and regulations to be adopted by districts within the basin. Once the council
adopts a NSR rule, each district in the basin is obliged by law to adopt and
enforce it, or to show cause why it should adopt an alternate rule. Thus, all
districts within a basin will have the same NSR rule unless the ARB and the council
agree that a particular district may deviate.

201

Special legislation established regional air pollution control districts for
the Bay Area and the South Coast Air Basin. The South Coast Air Quality Manage-
ment District (SCAQMD) is a recent creation which began its operations on
February 1, 1977, and assumed the powers and duties of the existing Southern
California-Air Pollution Control District. Ventura County and southern Santa
Barbara County, which had been part of the predecessor South Coast Air Pollution
Control District, are not included within the new entity. The legislation would
allow them to join the new SCAQMD, but neither is anxious to submit voluntarily
to the controls which will be applied in the new district, where ambient air
standards are exceeded over 200 days per year.

The SCAQMD was given responsibility under AB 250 to prepare and implement
at the earliest feasible date an air management plan to provide for the rapid
abatement of existing emission levels. The air management plan will incorporate
a regional plan, prepared by'the.Southern California Association of Governments
(SCAG), relati.ng to transportation, lan'd use, energy (production and development),
and other planning elements.

A I R Q U A L I T Y M A I N T E N A N C E P L A N N I N G

Areas which have the potential for exceeding any national ambient standard
within the period 1975-1985 are designated as Air Quality Maintenance Areas (AQMA)
for which an Air Quality Maintenance Plan (AQMP) must be submitted to EPA. The
AQMP must assess the anticipated growth in the area, project anticipated emissions
and identify-control strategies to achieve ambient air quality standards.

All of the southern California coast counties from Point Conception south to
the Mexican border are within designated air quality maintenance areas, as well
as the central coastal counties from Sonoma to Monterey, with the exception of
Northern Santa Cruz (see Figure 3). OCS activities off these areas will produce
,emissions which must be taken into account when future emission projections and
control strategies are developed.

Air Quality Maintenance planning provides a.forum for identifying trade-offs
needed to.achieve air quality standards. Since the plans must be approved by
ARB before they are included in the SIP and must then be approved by EPA in its
review of the SIP, the process can spotlight conflicts between OCS activity and
other growth and development. To the extent OCS-emissions can be anticipated,
their contribution to the violation of ambient standards must be offset by reduc-
tions from other sources. If their contribution cannot be completely offset, EPA
or ARB may require the imposition of more stringent area-wide controls. Santa
'Barbara and Ventura APCDs and the SCAQMD are all including OCS emissions within
their emission projections, since active leases lie directly offshore. San Diego
APCD 'is reluctant to raise its future emission estimates by including any OCS
contributions at all, because the numbers are so speculative: the county has no
current leases or production directly offshore and will not have any unless efforts
.to-oppose Lease Sale #48 or-to-have San Diego tracts eliminated fail.

A I R C 0 N S E R V A T 1 0 N P R 0 G R A M

The ARB is in-the early stages of developing an Air Conservation Program
.intended to protect areas of superior air quality-from degradation. The program
stems from EPA regulations-requiring the SIP to prevent significant deterioration
in areas where existing air was better than required by secondary standards.

I
EPA.s regulations focus on.protecting against particulate and sulfur dioxide

202

FIGURE 3:

STATE OF CALIFORNIA

AIR QUALITY NAINTENANCE AREAS

I. SAN DIEGO 5.TULARE
/> 2SOUTH COAST G.FFIESNO
A WIN
3RIVERSIDE-SAN BERNARDINO T. STANISLAUS-SAN JOA
4' KERN 8. SACRAMENTO METROPOLITAN
9, SAN; FRANrisco

A
"r-f

26
__j

. . . . . . . . . .

f
7-

4 *7 11

203

emission increases. In its initial stages, California's ACP may go beyond this
threshold, but will still be limited to primary pollutants such as sulfur dioxide,
particulate matter, hydrogen sulfideand carbon monoxide. Because the data base
is limited and the modeling techniques have not yet been validated, ARB staff
does not believe it is possible to predict the long-range transport of secondary
pollutants,.such as oxidant and nitrogen dioxide, in much of the non-urban area
covered by the program. 23/ The ARB, however, intends to expand the program to
all pollutants as soon as that becomes feasible.

The ARB has identified four classifications into which those areas of the
.state, with the exception of AQMAs where standards are not expected to be met,
will be divided:

Class A Least Deterioration Areas
Class B Minimum Deterioration Areas
Class C Agricultural and Silvicultural Areas
Class D Urban/Industrial Areas

The ACP will have no impact on OCS development from Point Conception south,
since these coastal counties are already designated AQMAs because ambient stan-
dards are not expected to be met. North of Point Conception, however, any off-
shore oil operations could conflict with ACP goals and classifications.

OCS AIR QUALITY IMPACT ASSESSMENT AND RESEARCH

An OCS air quality impact analysis of the Santa Barbara and Ventura County
areas represents an effort to make reasonable and accurate projections of the
effect OCS operations in the Santa Barbara Channel will have on air quality in
the adjacent coastal areas. The following discussion.identifies the methods
presently available for making this kind of assessment and indicates current
deficiencies in the assessment process. The concluding segment specifies certain
research priorities identified as necessary for improving the local APCD's ability
to make adequate OCS air quality impact assessments.

A I R Q U A L I T Y M 0 D E L I N G

The tool used most extensively in this kind of analysis is the air quality
computer simulation model. Air quality modeling is a systematic method for quanti-
tatively relating pollutant emissions from sources to pollutant concentrations
at receptors (locations where instruments measuring pollutant concentrations are
placed). The models are designed to simulate the action of the atmosphere in
mixing, modifying and transporting pollutants.

Models simulate the meteorology of an area -- particularly the wind patterns
determining the transport and dispersion of pollutants -- or the chemical trans-
formation of pollutants within a given air parcel, or both. The choice of model
is dependent on many factors -- most importantly, the type of source, the scale
of analysis desired, and the coordinate system used.

SOURCE TYPES

Point, line, and area are the three general source types. A point source

204

emits pollutants from one specific point in space -- e.g.-, power plants, storage
tanks, marine terminals. Line sources occur when pollutants are emitted at a
constant and uniform rate along a line, such as a freeway or heavily-traveled
street. The area source is-used when numerous small point and line sources result
in uniform emissions from an area. Urban areas and large parking lots are examples
of area sources. 24/ The facilities involved in OCS operations are all of the
point source types, but become area sources when clustered.

SCALES OF ANALYSIS

The scales of analysis for air quality modeling are the microscale, the
mesoscale,and the regional. Microscale analysis deals with the local effect
of a,single source or group of sources. The methodology for microscale estimates
is based on the Gaussian dispersion model and is usually applied to point and line
sources. The study area for a microscale analysis generally ranges from'one to
ten kilometers across in the direction of the average wi-nd. 25/

Mesoscale analysis is used to determine the effect of area and line sources.
The study area is delineated by a grid system, and source rates for each grid are
identified. This facilitates the estimation of pollutant dispersion.

Regional (or basin) analysis incorporates a grid system as well. This larger
Ts-
scale desirable when following the transport of primary pollutants that undergo
photochemical oxidation and then affect areas some distance from the source.
Regional models are based on solution of the conservation-of-mass equation, a
numerical solution involving the use of either a eulerian or lagrangian coordinate
system. 26/

COORDINATE SYSTEMS

The eulerian coordinate system is fixed to the ground. Models using the
eulerian solution are referred to as grid models, in which the study region is
divided into a three-dimensional array of cells. Each cell may vary from one to
four kilometers (0.6 to 2.5 miles) in a side and on the order of 10 to 100 meters
(33 to 330 feet) in height. The size of each cell will depend on the size of the
study area, on the spatial distribution of pollutant emissions, on terrain effects
that may alter surface winds, and on inversions. 27/ Each grid contains a des-
cription of the temporal and spatial distribution@__o_f both stationary and mobile
emissions, meteorological conditions, and initial air quality concentrations
either specified or calculated from known data. The conservation-of-mass equation
is then integrated to yield the pollutant concentrations within each grid for a
given time. I

The lagrangian coordinate system is attached to a fictitious vertical air
column moving horizontally on a trajectory determined by the direction of the
large-scale winds (see Figure 4). Models using the lagrangian solution are called
trajectory models, in which the column of air is followed through the study Area.
Air pollutants Are emitted into the column as fluxes at the ground surface, and as
it passes over the study area chemical reactions take'place within the column. 28/

GAUSSIAN MODELS

Gaussian models offer a more simplified approach to analyzing the distribu-
tion of pollutants. Models based on eulerian or lagrangian coordinate systems
can predict the distribution and concentration of both inert and reactive pollu-
tants on a regional level. Gaussian models, however, are applicable only for

205

Figure 4

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206

inert pollutants and only in microscale analysis. The Gaussian model is limited
to certain optimum conditions that enhance its predictive capabilities. It is
best applicable when:

1. wind flow is restricted to the horizontal direction;
2. sources and meteorology are not time-dependent;
.3. there are no terrain variations; and,
4. emissions are coming from a continuous and non-varying point source.

The spreading cloud of pollutants downwind of a continuous point source is
referred to as a plume. The plume constituents are normally distributed in the
horizontal and vertical crosswind directions. Figure 5 shows the coordinate system
used to describe the plume's distribution. The model used by Environmental
Research and Technology to determine the impact of non-reactive pollutants from
point sources in the Los Flores Canyon is based on the Gaussian distribution
depicted in Figure 2. Most Gaussian models use four assumptions to describe
the dispersion of emissions from a point source: 29/

1. the downwind concentration at any location is directly proportional to
the emission rate of the sources;
2. the more turbulent the atmosphere, the more rapid the spread of the
plume in the transverse direction;
3. the maximum concentration at ground level is found directly downwind on
the plume-line, and is inversely proportional to the downwind distance
from the source; and,
4. the maximum concentration decreases with higher wind speeds.

TRAJECTORY MODELS

In the ERT study, reactive pollutants contributing to ozone buildup from
Las Flores Canyon emissions and from offshore OCS activities were analyzed using
a semi-lagrangian model on a regional scale. The model computes the time-dependent
behavior of a moving air parcel in which a multi-component gaseous mixture undergoes
diffusion and photochemical reattion. As implied by the lagrangian formulation,
the air parcel carries its own set of coordinates in a trajectory aligned with the
wind direction and traveling at the prevailing horizontal wind speed. However,
surface emissions and pollutant levels beneath the trajectory are described tem-
porally (time of day, day of week) and spatially (by location) within a grid
system.

The photochemical subsection of the model considers the various chemical pro-
cesses occurring within the parcel as functions of species concentration, reaction
rate, and solar ultraviolet radiation. When these processes are combined with
background emissions and meteorological data the model then predicts how air
pollutants from a source will be distributed temporarily and spatially, as well
as their relative concentration at,a receptor.

The diffusion part of the model involves a wind field and dispersion analysis
that calculates an air parcel trajectory using surface wind data and a terrain
factor to account for physical barriers such as mountain ranges or large hills.
Of particular interest to our analysis are those trajectories that pass' over
present and proposed OCS development areas and later cross urban and/or indus-
trial land.

ADVANTAGES OF TRAJECTORY MODELS. Trajectory models, unlike Gaussian models,
require large amounts of detailed data for computers to simulate the movement of
an air parcel an'd the diffusion and photochemical reactions taking place within
the parcel. The more complex trajectory modeling offers certain advantages that

207

FIGURE 5:
COORDINATE SYSTEM SHOWING GAUSSIAN DISTRIBUTIONS IN THE HORIZONTAL AND VERTICAL

(x,-y,Z)-Receptor
(X'O'O)

6H
(X"-Y,O)

y
h

h = Actual Stack Height
H = Effective Stack Height
AH = Initial Plume Rise Due to the Buoyancy
and momentum of Stack Gases
u = Mean Wind Velocity and Direction

SOURCE: D. Bruce Turner, Workbook of Atmospheric Dispersion Estimates,
U.S. Department of Health, Education, and Welfare, 1970, p. 5.

208

the simplified Gaussian approach does not. 30/ It has the capability to:

1. make project-level arralysis;
2. locate sources that produce hot spots (areas of high impact) for pollu-
tant emissions;
3. predict pollutant concentrations in valleys through simulation of air
movements; and,
4. analyze areas where terrain affects surface winds.

It is also less costly to simulate a single trajectory than to analyze the
transport and diffusion of pollutants over an entire grid.

LIMITATIONS OF TRAJECTORY MODELS. Under certain conditions the use of tra-
jectory models is inappropriate. All computer models are limited to the amount of
data available as well as to assumptions about the atmospheric conditions
which they simulate. Trajectory models have the following limitations:

1. they are not applicable where vertical wind shear is an important
consideration;
2. because of this exclusion of vertical winds, they are not directly
applicable when working with convergent or divergent wind flow fields;
3. they are not applicable to multi-day runs;
4. the trajectories calculated are sensitive to the exposure of wind
.stations; therefore, surface wind data must be consistent
with model assumption;
5. current models do not incorporate elevated point sources; and,
6. large volumes of data are required. 31/

INPUTS TO TRAJECTORY MODELS. Trajectory models applied on a regional scale
and incorporating photochemical reactions require a huge body of information about
emissions, meteorological factors, and air quality. A model's abili.ty to simulate
events in the atmosphere with a. high degree of confidence is directly enhanced by
the quantity and quality of the data base.'

The.following discussion evaluates emissions inventories, meteorological
data, and initial concentration fields, as well as detailing the problems with
using existing air quality bases.

EMISSION INVENTORY

An emission inventory provides estimates, by category, of vehicular, air-
craft, power plant, refinery, and distributed area sources, including their tem-
poral variations. The emission sources spatially distributed over a grid system
have@a temporal resolution of one hour, since air.quality standards are generally
based on a one-hour exposure time.

For-the emissions inventory, the following information is required: 32/

1. Vehicles

a. spatial distribution of daily vehicle miles traveled (VMT);
b. temporal (hourly) distribution of vehicle miles traveled;
c. average emissions rates (mass/distance) of CO, NOx, and HC;
d. spatial and temporal-distributions of average vehicle-speed;
e. variations in emissions rates with average speed for CO, NOx,
and HC; and,

209

f. 'effects on average emissions rate of cold-start and hot-running
operations.

2. Aircraft

a. ground operations emissions rates of CO, NOx, and HC as a function
of traffic level, mode of operation, aircraft class or type,
location, and tim*e; and
b. flight operation emissions rates as a function of the same variables
as those for ground operations including taxiing, landing, and
take-off.

3. Power Plants

a. emissions rates of NOx fo r each plant as a function of type of fuel
burned, time of day, and time of year;
b. emission rates of NOx and organic gases for each
refinery; and,
c. emission rates of CO, NOx, and organic gases as a function of
location for distributed stationary sources.

For all of the above emission inventories, the ratio of NO to N02 is also
needed.

In order to evaluate the impact of OCS developments on air quality, OPR
entered into an agreement with Santa Barbara and Ventura counties Air Pollution
Control Districts (APCDs) to update their emission inventories of major gaseous
pollutants and particulates arising from stationary (point and area) and mobile
sources in the county. In the process of accomplishing the emissions inventory,
the Ventura APCD selected the following method:

Task 1. Preparation of Inventory Format

a. Classification of all known stationary, mobile, and area sources
of pollutants within the county.
b. Identification of sources of information for the inventory.
c. Development of questionnaires, field data sheets, and emission-
source summary sheets.

Task 2. Development of Inventory

a. Training of extra-help employees to review sources of data for the
inventory, and assignment of specific tasks.
b. Compilation of emission inventory of the known stationary sources
emitting more than 0.1 tons per year of pollutant. Registration of
the data in EPA's EIS format. Sources for the data include APCD
permit files, field surveys, field inspections, interviews, litera-
ture.surveys, County Planning Department publications, and ARB
files.
c. Compilation of mobil source inventory. The best data source for
this inventory (unavailable at the time of the Ventura.County analy-
sis) is a Caltrans study of recent vehicular traffic in the South
Coast Air Basin. This-study supplies average daily travel (ADT) in
miles, by link (any road segment between intersections). These data
are then made compatible with the Universal Transverse Mercator
(UTM) location system.- using 1X1 kilometer grids and -a grid

210

aggregation interface program developed by the ARB., The result
of this program gives mobile emissions ( in tons per day) for each
UTM grid square. The Caltrans data on normal daily peaks in
vehicle traffic allow this program to reflect temporal variations.

Task 3. Storage of Data on Magnetic Tape

In order to make optimum use of the information obtained in Task 2,
the data.are stored on magnetic tape in the format of
EPA's Emission Inventory System through the-Comprehensive Data
Handling System, Emissions Inventory/Permit and Registration Subsys-
tem (EIS and P&R) Program. The information is also stored in a
form compatible with similar data obtained in other areas along
the South Coast. This integrated data base can then be used
for evaluations of onshore impacts on air quality of,pending
offshore oil developments in southern California waters.

GRID SYSTEMS

Because a grid coordinate system is more appropriate for large areal
analysis than the Gaussian, the logical choice of grid system for OCS analysis
is one based on an areal emissions inventory using a data-base appropriate to
trajectory models. The grid parcels can be virtually of any size and shape,
but the UTM grid square system offers certain advantages: all grid squares.are
of identical size and shape, and good resolution is obtainable-even with the
relatively large-size grid (lXl km) employed at Santa Barbara.. Resolution
improves as grid size is reduced, but computation time increases. Thus, the
analyst must make a trade-off between fineness of resolution and complexity.

Before choosing a grid size, the study region -- and hence the grid-bound-
aries -- must be defined. Because of the multidisciplinary expertise required to
develop data for the model, the boundary selection for an area should be coor-
dinated with local land-use planning agencies, APCDs.,.and transportation planners.,
Major factors to consider in defining the'region should include: (1) populated
areas; (2) areas of,high pollutant concentrations; (3) areas of high emissions;
(4) topography and terrain features; and, (5) local master plans for future
developments. 33/

METEOROLOGICAL DATA

The meteorological data needed for the-model must include the follow-
ing comprehensive information:

1. wind speed and direction -- both at the surface and aloft as a function
of location and time;
2. temperature -- as a function of height (to permit estimations of stability),
location of the inversion layer and inversion base, and strength of the
inversion;
3. -vertical turbulent diffusivity in terms of height,.ground location-, and
time of day. This is estimated-as a function of the following
variables: turbulent energy dissipation rate, wind shear, vertical..,
temperature gradient, wind speed, and surface rQughness;.and
4. isolation as a function of ground locations, elevations, and time-of
day.

1_1-76658 211

The meteorological data used for the wind field and dispersion analysis in
Santa Barbara were gathered from a variety of sources. Data utilized were from the
National Weather Service (NWS) stations,. Vandenberg AFB (surface and upper air
data), and Federal Aviation Administration airport data.@ Star printouts were
obtained from the National Climatic Data Center in the form of stability-wind
roses,giving monthly and annual frequencies of wind-speed and direction as func-
tions of Pasquill-Gifford stability class. Such information allows simultaneous
assessment of both trajectory and dispersion characteristics for long-term average
cases. The wind information was then converted to IBM system format.

Past meteorological data for any area in California are also available from
the Meteorological Department of the ARB. Their data contain all weather observa-
tions, available for every hour or for every third hour. In cost-benefit terms,
a broader base of wind information has significant advantages over information on
the temperature structure of the lower atmosphere: ten wind stations can be pro-
vided at the same cost of a single temperature station, supplying information that is
much greater in quantity and more useful.

INITIAL CONCENTRATION DATA

Air quality data required.to establish initial concentration fields at the
surface and aloft for a full three-dimensional simulation are: concentrations for
CO, NO, N02, 03, total hydrocarbons (THC), and reactive classes (RHC).
In summary, then, the amount and quality of data needed for an air quality
simulation model are dependent on: (1) the availability of a complete and up-to-
date emissions inventory for the area; (2) the number of surface air quality and
meteorological monitoring stations and their locations; and, (3) the frequency
of measurements of vertical temperature profiles and of wind and air quality
aloft.

.L I M I T S T 0 M 0 D E L I N G A P P L I C A T 1 0 N S

'Urban areas with a number of air monitoring and meteorological stations may
already have a sufficient emissions inventory and an aerometric data base to use
in photochemical models. However, before deciding to use a model based on the
existing data bases, an APCD should be able to answer the following questions: 34/

1. Are the air and meteorological monitoring stations located so that they
measure representative data consistent with model assumptions describing
the temporal and spatial distribution of surface winds and air quality?
2. Are the air monitoring networks located@near a localized source of
pollutant emissions?
3. Is there a standardized height above the ground for the entire
network from which the air and meteorological measurements are made?
4. Are the recorded hourly values of air quality concentrations and surface
wind measurements based on an integrated hourly average or on instantan-
eous reading?
5. How often are the air and meteorological instruments calibrated to provide
quality assurance control of the data.collected?
6. Are stationary source inventories up to date?
7. Is.the.velhicular emission inventory ba.sed on the latest emission factors
published by-EPA?
8. Is the transportation simulation model used to predict vehicle kilometers
traveled sensitive to changes in gasoline prices, availability of mass
transit alternatives, and future trends in population growth?

212

If answers to the above questions are unsatisfactory, a significant invest-
ment to obtain baseline data must be made before a computer s'imulation model
can be used to project air quality impacts with any accuracy.

EXISTING EMISSIONS INVENTORIES

In California, emissions inventories for mobile and stationary sou@ces are
prepared by different agencies. The California Department of Transportation
(Caltrans) develops the vehicular emissions, while the APCDs and ARB develop sta-
tionary source emissions. All stationary source emissions have a numerical
description (geo-code) indicating their location within an area. One problem in
using these data has been that there is no standard format. Each agency has
evolved its own coordinate system to geo-code emission source. As a consequence,
preparing trajectory models that use a variety-of agency sources has been difficult.
Other problems-that arise in obtaining emissions data are: 35/

1. the highway cruse model of emission factors as published by the EPA
does not always represent actual conditions;
2. the aircraft emission data, as.required by air quality models, are
generally not available;
3. stationary source inventories are commonly two to three years behind
current conditions; and',
4. no consistency exists in defining reactive hydrocarbons. The State
ARB has recently established a three-class system of reactivity that
will make it even more difficult to use second generation kinetic
mechanisms in models that grou hydrocarbons into five classes:
(1) methane, (2) paraffins, N olefins, (4) aromatics, and
(5) aldehydes.

EXISTING METEOROLOGICAL DATA BASES

The existing sources of meteorological data for use in regional models are
primarily airports, APCD 'air monitoring stations, and nearby military bases. The
meteorological data monitored consist of surface wind speeds and directions, and,
in some instances, information from two daily rawinsonde releases measuring the
vertical temperature. In evaluating the existing data, it is important to keep
in mind that the meteorological data will be used to calculate the representative
one-hour wind flow fields on a temporal and spatial basis for each grid of the
whole study area. Similarly, the temperature measurements must be able to repre-
sent and describe the temporal and spatial changes of inversions for the entire
area.

The following problems arise when using existing data:

1. in most areas there are too few ground stations to describe the surface
wind flow field;
2. the instruments monitoring surface winds are often insensitive to
speeds of less than 3 miles/hour;
3. the readi-ngs recorded at airports are generally instantaneous and do
not represent the one4our average;
4. the APCD wind stations, generally -located atop buildings, monitor the
localized air flow around and over the building rather than the repre-
sentative surface winds;
5. in regions where terrain alters the inversion by thermal heating, one
or two rawinsonde releases are not representative for the region, nor
are they sufficient to describe the temporal behavior;

213

6. virtually no measurements are made of winds aloft; @nd,
7. measurements of insolation are rarely made, and then only at one location,
making it difficult to account for spatial variation of radiation
intensity in large urban areas. 36/
EXISTING AIR-QUALITY DATA BASE

The air monitoring network in California consists of a system of ground
stati.ons developed during an earlier, simplistic stage of the art. For the most
part, the stations were built where land was cheap and were located relatively
close to each other to make it easier for technicians to service the instruments.
These stations were not located or intended to provide -- either individually or
collectively -- anything like a representative sampling of regional air quality.

Briefly sketched, the generic inadequacies of these stations are as follows:

1. they are insufficient in number to describe the temporal and spatial
distribution of pollutants needed to establish initial concentration
fields or to verify operative models;
2. they exhibit no standards for placement of air intake or for location.
Most are located near arterial thoroughfares and have low intakes, designed
to monitor vehicular exhaust: thus they register unusually high concen-
trations of CO, HC, NOx, and Nb2, plus abnormally low 03- When they are
located atop tall buildings the reserve obtains: low CO, HC, and NOx con-
centration, high 03. Readings of these kinds are clearly not sufficiently
representative for regional modeling;
3. air quality measurements aloft are virtually lacking in urban areas,
although the information collected is important in determining initial
concentration fields and is necessary for monitoring 03 buildup beneath ele-
vated inversions that can vary from one day to the next;
4. instrumentation is not standardized among the stations. In some urban
areas wet chemical methods are used, in others dry techniques or a combin-
ation of the two. Careful correlation is required if these disparate data
are to be used;
5. presently lacking is a program of frequent calibration of instruments,
necessary to assure the quality of data retrieved; and,
6. all stations within the network must be equipped to monitor reactive (RHC)
and total hydrocarbons (THC). Presently, many stations lack this capabil-
ity. @7/

0 C S E M I S S 1 0 N S

Baseline meteorological and air quality data are the primary ingredients of the
computer model. Once this information is processed, the model can be used to simu-
late the effect of emissions from the various types and intensities of OCS activity
and development. Emissions of NOx, CO, S02, TSP, THC, and RHC can all be analyzed
under both normal conditions and abnormal ones (spill's, blowouts, etc.).

With normal OCS operations, it is necessary to identify all sources where
emissi'ons will occur or are likely to occur. For every source, an emission factor
is then determined and applied to the throughput of oil and gas for each activity
(production, transport, treatment, storage, etc.). A given volume of throughput,
multiplied by the emission factor of the appropriate source for these operations,

214

yields a number representing the amount of pollutants released. Specific emission
factors are employed for each particular pollutant emanating from a source.

Emission factors for the following OCS operations and emissi on sources were
used to arrive at pollutant levels for the ERT analysis included as part.
of this report:

Platform Emissions

1. diesel engines;
.2. wastewater separation;
3. turbine natural gas compressor (fugitive emissions);
4. pump seals;
5. compressor seals; and,
6. relief valves.

Tanker Emissions

1. loading (fugitive);
2. transit (engines).;
3. berthing (engines);
4. ballasting; and,
5. vapor emissions from loading.

Natural Gas Production

1. H2S; and,
2. S02-

In addition to the pollutant sources listed above, emissions resulting from oil
spills of various magnitudes were modeled as well.

.The present status of emission factors is far from ideal: they are both -
incomplete and of questionable reliability. Many of the EPA's emission factors
are outdated due to.changes in technology and improvements in research techniques.
Published emission factors for OCS activities are particularly disparate and un-
satisfactory. They are either conflicting (as between the EPA and the oil
industry) or non-existent.

R E S E A R C H P R 1 0 R I T I E S

Limitations of data, funding, and time preclude opportune development of any
complete, detailed analysis of air quality impacts from OCS-related activities and
development on southern California. However, the information and experience
gained in this study should enable state and local agencies to identify data gaps
and determtne research priorities for improving their assessment of OCS impact.
The resumption of drilling and development activity in Lease Sale #35 and the
imminence of further OCS leases off California render this improvement in analytic
capability absolutely essential if OCS development is to proceed without serious
degradation of California air quality.

Given funds and time, the most important items for further research of OCS
impact on air quality -- as identified by APCDs in order of priority -- are:

1. determination of reliable oil-production emission.factors;

215

2. determination of wind, inversion, radiation characteristics, and temper-
ature profiles between oil production sources and major receptor areas;
3. determination of optimum locations and standardized instrumentation for
air monitoringstations;
4. determination of reliable projections of oil throughputs, including
tract locations, projected tanker loading locations and schedules, pipe-
line locations and throughputs, projected storage sites, and storage
tank characteristics and throughputs; and,
5. use of the data base outlined in (1) through (4) to model the
impact on air quality from current and projected OCS oil production
activities.

The Santa Barbara and Ventura county APCDs, in their responses to an OPR
questionnaire, identified specific types of needed research. Emission factors are
required,for the following areas of OCS activity:

1. offshore operations where vapors escape as fugitive emissions from well
heads, production manifolds, crude processing equipment, and maintenance
procedures;
2. onshore processing and crude oil treatment where vapors are generated;
3. transferring products to large storage vessels where vapor volume dis-
placement and working losses occur;
4. tanker loading and ballasting; and,
5. problems or accidents involving any of the above.

Both counties noted that the lack of meteorological and emission data severely
hampers prediction of air quality. The quality of data presently collected
at fixed air monitoring stations and airports does not enable accurate assessment,
particularly of NOx and RHC.

These county APCDs identified, as the optimum tool for predicting the effect
of OCS emissions, a mobile monitoring system with portable ambient air quality
measuring equipment supplying both meteorological and emissions data. The layout
and costs for such a system proposed for use by the Santa Barbara APCD are as
follows:

Syst em I: Ambient Air Quality Monitoring Van

Estimated Cost

Design Engineering and Interior Layout $12,000

Monitoring Equipment
Hydrocarbon analyzer, oxides of nitrogen
monitor, ozone monitor, sulphur dioxide
monitor, hydrogen sulphide monitor, carbon
monoxide sampler and analyzer, Hi-Volume
sampler, coefficient of haze meter 48,000

Sample Gathering, Conditioning and Dilution System 8,000

Meteorological Data System 5,000

Control Systems 8,000

216

Estimated Cost

Recorders $ 6,000

Calibration Gases and Sources 4,000

Special Lord Mounts for Instruments 2,000

Power Supply and Conditioning 2,000

GMC Van 22,000

System Installation and Integration 25,000
(Vehicle modification $ 8,000)
(Electrical and instrument installation 12,000)
(Equipment test and check-out 5,000)

Support, Maintenance, and Indirect Charges for 2 yrs. 30,000

Total Estimated Cost $177,000

This system would provide the minimum mobile capacity to measure hydrocarbons,
the primary air pollutant from oil production operations. By moving the monitoring
System I to appropriate locations,.adequate onshore data for diffusion modeling can
be obtained.

The Santa Barbara APCD estimates a six-month procurement and assembly time for
System I -- two months to clear County procedures, four months assembly time. It
would take almost a year before data are reduced, processed, and introduced into a
model for consideration in OCS impact assessment. However, an alternative assembly
of minimal equipment could be implemented in 60 to 90 days at a cost of $37,000 to
$40,000, plus vehicle costs. Data from this interim system could be available in
less than six months. The details for System II are given below:

System II: Hydrocarbon Mobile Monitor

Estimated Cost

Hydrocarbon Analyzer 0-100%, NOIR $3,000

FID Hydrocarbon Analyzer 0.01 to 10,000 ppm 6,000

Chromatagraphic Analyzer 0.001 - 100 ppm 10,000

Power Supply and Conditioning Equipment 3,000

Meteorological Portable Units 3,000

Equipment Integration and Installation 7,500

Engineering Design 4,500

Chart Recorders 1,500

Subtotal Equipmen t $38,500

217

Unit A

Chevy 1/4 T Van plus Above Equipment $46,500

Unit B

GMC Travel Van plus Above Equipment $60,500

A mobile monitoring program, such as either of the systems detailed above,
can also measure such oil-related items as:

1. onshore hydrocarbons (HCs) near-platforms;
2. seep effects from OCS added HCs;
3. tanker emission effects;
4. crude storage emissions;
5. fugitive emissions;
6. upset condition measurements; and,
7. sour gas impact projections.

Santa Barbara needs to expand its air monitoring network to provide baseline
information for quantifying and.forecasting air quality. An adequately articulated
network could perform the following tasks:

1. quantify the.existence of present air contaminants;
2. establish a chain of measurement stations on and off the South Coast;
3. provide data links, control handling, and central processing;
4. increase the meteorology base for greater impact trajectory coverage;
5. prepare data for air quality models; and,
6. improve the methodology base for air quality assessment.

The baseline information, together with the mobile monitoring program, would
make possible the development of fully rationalized measures for minimizing OCS
.effects and preventing air quality degradation.. The data generated from the
program proposed by the Santa Barbara APCD would-greatly assist in the establish-
ment and verification of emi'ssion factors for OCS-related sources and would provide
information and.methods applicable to the entire west coast.

Substantial improvement of baseline information on.pollutant levels, emission
sources, and meteorological conditions would enable better trajectory modeling for
the Santa Barbara/Ventura coastal areas. With this information, and adequate
funding, several combinations of petroleum development could be modeled. The
effect of current, increased, and reduced tanker usage and loading could be
analyzed-and modeled, along with such alternative measures as pipelines-and new
loading/uh-loading-techniques -- e.-g., the use of inert gas to displace oil in
tanks.

Receptor-oriented trajectories (possible only with mobile receptors), instead
of the usual-source-oriented trajectories, have been suggested for particularly
.sensitive or critical onshore sites -- scho6ls, residential areas, air monitoring
stations. Advantages of this approach include the ability to analyze all hours
rather-than merely the time of trajectory-passage (or "worst hour"), to produce a
ranking of,hours by concentration of pollutants, and to calculate total day-dosage
at the receptor.

218

A study has also been proposed to break Santa Barbara County HC emissions
into reactivity classes. A mean reactivity (expressed as Source Molar Reactivity
or Source Weight Reactivity) would be assigned for each UTM'grid square, as well as
masses of emittants by class for all squares. Reactivity/mass figures for critical
point sources (such as OCS facilities) would be determined.

219

PART TWO: AIR QUALITY IMPACTS
OF OUTER CONTINENTAL SHELF DEVELOPMENT
IN THE SANTA BARBARA CHANNEL*

The Santa Barbara Channel is at once both a potential source of crude oil
and natural gas and a sensitive environmental area. The Channel, wi.th its sig-
nificant quantities of oil resources, became a major focal point for new produc-
tion following the reduction in supply and escalating price of foreign crude in
1973-74 -- the period of the "energy crisis."

But this was also the period of greatest environmental concern this country
has ever seen. Many new environmentally oriented agencies, both public and pri-
vate, came into existence, and legislation aimed at preserving or attaining high-
quality environmental conditions increased significantly. In addition, certain
events, particularly the 1969 Platform A blowout in federal waters off Santa Barbara,
created strong local anti-oil feelings and spawned several citizen groups whose aim
was to limit-or eliminate Channel oil development.

California, which consumes more vehicle fuel than any other state, is particu-
larly vulnerable to a shortage of oil and gasoline. Nevertheless, concern for
clean air, clean water, and a healthy biota is widespread. Despite extreme pro-oil
viewpoints, many citizens and organizations recognize that a compromise between
energy production and environmental quality may indeed be achievable. No longer
can the various aspects of the situation be considered independently; economics,
quality of life, and quality of environment are in most cases interdependent, and
any realistic analysis of one aspect must consider the others.
The present study was initiated at the request of the State of California
Office of Planning and Research (OPR) and the Santa Barbara.County Office of
Environmental Quality (OEQ). Analysis of the impacts of current and future OCS-
development upon the air quality of coastal regions was the subject of the inves-
tigation. Several tasks were conducted in the course of the project: available
data on air quality, meteorology, and emissions were collected and edited; estimates
of future offshore production were obtained from industry and public agencies;
photochemical smog (ozone) impacts were modeled using a chemistry/photochemistry/
diffusion model; and, primary pollutant concentrations were determined using a
Gaussian-type analysis scheme.

.Prepared for the California Governor's Office of Planning and Research and
Santa Barbara County Office of Environmental Quality by George H. Taylor, Environ-
mental Research & Technology, Inc., 2030 Alameda Padre Serra, Santa Barbara,
California 93103.
The author expresses appreciation to the following agencies and individuals for
their assistance in contributing or providing data necessary for successful comple-
tion of the project: the Governor's Office of Planning and Research (Suzanne Reed,
Trevor O'Neill, Allan Lind,); Santa Barbara County Office of Environmental Quality
(Al McCurdy); Santa Barbara County Air Pollution Control District (John Laird);
Ventura County Air Pollution Control District Doug Tubbs, Bill Thuman, Craig
Barberio, Dave Barnes); CALTRANS headquarters Nichard Salmen); and Exxon, U.S.A.
(through Bruce Wales, Dames & Moore, Inc.). In addition, the.help of ERT staff
members Alan Eschenroeder, Richard Nordsieck, Khanh Tran, Veda Bohlander, and Alan
Lloyd is greatly appreciated.

220

This report is intended to identify local areas which would be most adversely
affected by future OCS' development, to determine the magnitude of such air quality
problems, and to provide decisionmakers with measures to mitigate those impacts
in the most efficient and economically desirable manner possible.

SUMMARY
Air quality impacts of Outer Continental Shelf (0(;S) petroleum industry
development in the Santa Barbara Channel upon the Counties of Santa Barbara and
Ventura were assessed using the ARTSIM photochemical/diffusion model, which pre-
dicted concentrations of reactive pollutants, and the PSDM diffusion model, for
primary pollutant modeling. ARTSIM modeling stressed ozone formation resulting
from two emissions effects: ambient background levels of precursor substances,
which represent day-to-day carryover effects; and, local-scale point source impacts,
in which downwind in-plume concentrations resulting from emissions from Platforms,
treatment facilities, and marine terminals were mode *led. In addition, the increase
in ozone from hydrocarbon emissions from natural oil seeps and an accidental
oil spill was assessed. PSDM calculations focused on levels of sulfur dioxide and
hydrogen sulfide in the vicinity of large emitters of these substances.

Changes in ambient background.1concentrations of ozone precursors (notably
hydrocarbons and oxides of nitrogen) were estimated for three levels of possible
Channel oil development: existing facilities only; moderate increase in the num-
ber of facilities and total production; and, heavy development and production.
Results of the simulations indicate that, with only existing facilities in opera-
tion, future study area ozone concentrations would be significantly lower than
current levels, due to declining production of the petrole.u'm leases and reductions
in vehicle emissions as a result of more stringent vehicle pollution standards.
Moderately increased future development, with its corresponding increases in emissions,
would offset auto emissions decreases and result in ozone levels very similar to
those currently observed. Heavy increases in development in the Channel would yield
ozone concentration significantly higher than at present.

During point source simulations, it was observed that tanker loading activi-
ties represented the most significant local source of ozone-forming precursors.
In addition, accidental spills of oil on the sea could lead to large increases in
downwind ozone levels.

Concentrations of sulfur dioxide and hydrogen sulfide could, in some cases,
exceed ambient air quality standards in the vicinity of large treatment and sepa-
ration facilities, according to PSDM simulations. Emission control and/or limita-
tions of facility size were suggested as means of reducing such concentrations.

Mitigation of ozone impacts could be accomplished by: limiting development
of Channel oil/gas leases; using pipelines rather than tankers for transport; and,
utilizing onshore rather than offshore sites for storage and handling to reduce
routine loading/storage emissions. If tankers are used in the Channel, mitigating
measures could include: loading partially (15,feet was suggested as final ullage
distance); loading slowly; and, limiting simultaneous tanker loadings to one within
any predetermined radius of influence (estimated at 25 miles for the Santa Barbara
south coast).

221

Finally, it was suggested that the local meteorological data base be expanded
significantly in order to improve the validity of future air quality impact studies.
In particular, additional surface and upper7air wind data stations should be
set up.

COMMENTS ON PREVIOUS AIR QUALITY IMPACT ANALYSES
FOR SANTA BARBARA CHANNEL AND VICINITY

0 1 L A N D G A S D E V E L 0 P M E N T I N T H E S A N T A B A R B A R A
C H A N N E L 0 U T E R C U N T I N E N T A L S H E L F 0 F F C A L I F 0 R N I A
U N I T E D 'S T A T E _SG E 0 L 0 G I C A L S U R V E Y , 1 9 7 6

In its impact analysis of Santa Barbara Channel Oil and Gas Development, the
USGS has presented a comprehensive overview of every concei-vable oil- or gas-related
effect. In formulating such an all-encompassing document, however, some topics
have been covered in a cursory manner: air quality impacts,, in particular, suffer
from this inadequacy.

. The most glaring example of inadequate assessment of impacts concerns formation
of photochemical smog, of which oxidants (notably ozone) are primary constituents.
Admittedly, oxidant formation, involving a complex array of chemical and photochemi-
cal reactions, is rather difficult to quantify; notable among the more simple models
are those relating precursor concentrations (HC and NO.) to peak oxidant, as in the
well,known "roll-back" modeling. In the USGS document, however, even the relatively
simple procedures have been ignored. The discussion in question (page 111-217)
begins

In terms of smog formation, the paraffin hydrocarbons emitted
from the cargo holds during loading are expected to yield less oxidants
than an equivalent amount of vehicular emissions. Vehicular sources emit
substantial amounts of aromatic and olefinic compounds, both of which
yield higher oxidant concentrations than an equal amount of paraffinic
compounds.

True enough, and well stated, although vehicle emissions tend to be spread over
wide area:s and are relatively steady, while tanker loading emissions are intermittent
and essentially point-source in nature. It is shocking, therefore, to read the
sentence immediately following the above passage:

Thus, marine terminal operations are expected to have only a minor
impact on regional air quality.

This statement grossly understates potential oxidant impacts of tanker loading.
Although admittedly less reactive than vehicular exhaust components, tanker load-
ing HC is emitted in such large quantities that downwind ozone concentrations can
be severely affected by the reactive HC fraction (which can exceed 1,000 lbs/hr
during loading operations). The real problem, then, is the local effect, and to
deny its importance using the logic exhibited above is certainly not valid.

222

SOUTHERN CALIFORNIA OUTER CONTINENTAL SHELF
OIL DEVELOPMENT : ANALYSIS OF KEY ISSUES
ENV_rRONMENTAL SCIENC E AND ENGINEERING
UNI.VERSITY OF CALI FOR-N IA , LOS ANGELES , 19 76

The approach used in this document for modeling air-quality impacts of OCS
development is considerably more comprehensive and scientifically defensible than
that utilized in the USGS document. In addition to assessing impacts of routine
emissions, Environmental Science and Engineering (ESE) has included oil spill and
oil fire impact analyses, as well as a discussion of chemical and photochemical
mechanisms involved in oxidant production. Primary pollutants (e.g., CO, S02) are
handled by means of Gaussian-type modeling, generally a valid approach over such
homogeneous terrain as the ocean and level coastal plains.

The most serious deficiency in the ESE report involves photochemical smog
analysis. ESE's approach is to treat oxidant production solely as a function of
reactive hydrocarbon concentrations, with particular emphasis placed on attainment
(or nonattainment) of the 160 pg/m3 with three-hour federal standard. Since even
the most simple oxidant models in common use treat peak oxidant concentration as
a function of morning levels of both RHC and NOx, ESE's method seems unduly simpli-
fied. ESE's statement that "the federal standard . . . is the level needed to
assume an ozone limit of 0.09 ppm" is simply not a valid one in all areas and
ci rcumstances.

In conclusion, then, ESE's major air quality shortcoming lies in its
scientifically invalid analysis of what is probably southern California's major
pollution problem, photochemical smog. Impacts of other pollutants are discussed
in a thorough, valid manner.

0 N S H 0 R E I M P A C T 0 F 0 F F S H 0 R E S 0 U T H E R N C A L I F 0 R N I A
0 C S S A L E # 3 5 G 0 V E R N 0 R - S 0 F F I C E 0 F P L A N N I N G
AND RESEARCH @1976

In its appraisal of OCS air quality impacts, OPR drew heavily from previous
EIR publications and included very little original analysis or interpretation. As
such, the document suffers from the deficiencies of its predecessors: in particular,
oxidant impact analysis is treated in a cursory and, at times, incorrect manner.

The oxidant impact approach used in the OPR report is similar to the ESE method
discussed previously: the nonmethane hydrocarbon (NMHC) standard is used in lieu of
the more complex photochemical analysis. As stated in the previous section, this
approach can be viewed as an oversimplification of what is a complex local and re-
gional problem affected by a number of distinct variables.

The OPR report is valuable chiefly as a review of existing impact assessments
and emissions characteristics, despite its shortcomings with regard to photo-
chemistry. Reviews of air quality trends and legal aspects are of particular merit.

223

ENVIRONMENTAL SETTING

GEOGRAPH I CAL CHARA,CTERI STI CS

The Santa Barbara Channel, lying east-west, is located
approximately 170 kilometers nort hwest of Los Angeles. Bounded on the north by
the southern Santa Barbara County coastline, on the east by the Ventura County
coast, and on the south by the Channel Islands (Anacapa, Santa Cruz, Santa Rosa,
and San Miguel), the Channel measures roughly 110 kilometers in length (east-west
dimension) and 40 kilometers in width. The Outer Continental Shelf (OCS) portion
of the Channel, comprising those areas more than three miles from mainland and
Channel Island shorelines, is under federal jurisdiction; as of January 1, 1973,
about 40% of the Channel OCS acreage was held by federally issued oil and gas
leases. 38/

The south coast of Santa Barbara County consists primarily of an east-west
oriented coastal plain, generally less than eight kilometers in width, backed by
the Santa Ynez mountains, whose crest averages about one kilometer in elevation.
The coastal plain, which is cut by numerous small, seasonal streams, is widest
(about ten kilometers) near the city of Santa Barbara. Along much of the shore-
line, narrow sand beaches front steep 20- to 30-meter sea cliffs. Between Santa
Barbara and Ventura, the coastal plain is discontinuous and generally less than
three kilometers in width. 39/

The eastern shore of the Channel, extending from Ventura to Point Mugu, is
characterized by a wide coastal plain of low relief extending about 15 kilometers
inland. In addition, several alluvial valleys penetrate the mountainous areas
to the north and east; the major such valleys comprise the drainages of the Ventura
and Santa Clara Rivers, Arroyo Las Posas, and Arroyo Santa Rosa.

The Channel Islands, an east-west chain about 100 kilometers in length, form
a seaward extension of the Santa Monica Mountains, which terminate ashore at
Point Mugu. Santa Cruz, the largest of the islands, is approximately 38 kilometers
in length.,

Underwater topography in the Channel comprises several distinct regions:
.the Santa Barbara Basin, lying in the center of the Channel and reaching a depth
of 625 meters; the Mainland Shelf, a submarine terrace paralleling the coast and
varying in width from four to five kilometers west of Santa Barbara to 20 kilo-
meters off western Ventura County; the Channel Islands Shelf, which extends
approximately four kilometers northward from the island chain; the Goleta and
Oxnard slopes, which separate the Mainland Shelf and the Santa Barbara Basin; and,
the Channel Island Slope, lying between the Basin and the Channel Island Shelf.
Other notable marine features include the Pescado Fan, Dos Cuadras Ridge, Twelve-
Mile Reef, and Hueneme and Mugu Submarine Canyons.

Figure I is a map of the study area, showing the Santa Barbara Channel and
surrounding onshore areas as well as the three-mile boundary which separates state
tidelands from federal OCS waters.

M E T E 0 R 0 L 0 G I C A L C H A R A C T E R I S T I C S

Prevailing large-scale circulation along the Santa Barbara-Ventura coast
results in predominant westerly to northwesterly air flow throughout the year.

224

FIGURE.1:
BASE MAP, SANTA BARBARA CHANNEL AND VICINITY

Jalam

SANTA BARBARA C
Con@@prion a,iota iigLl 5

N le

191 18 Pt o tec
oal il pt
7 196 r Go
194 190
Santa arbara arpint r

85 184 183 181 180

166
241 240

'238 237 235 234 233
],,RON
S Ai
vi
179,, 178 177 A 2i@- i@ 228 2
232 231 2 27 226
V\

176 175- 1714.
223, 222 221 218 217

171
173 ............ . . ..... ... ...
170 17i IV
213 212 -V2,6' 210
169
... . ...... :Z206 201 200
H,,, ris pt 168
167 . . . ......

Flascr pil
SAN MIGUE Dianlo Pt
Pt Bennett ISLAND
Card@ell Pt Ca, rington pt Coche Pi.
San Pedro F1
"Ki .-Swidy Pt
SA'V-rA CRUZ ASLAT4D
Skunk Pt

........ . .
0@en Pt.
ROSA ISLAND C'mors
ast pr. . . ... ..... .......
Cluster Pt . ..... .
\X`11
sokah pt

26 1,

r
32 33 34
-@o
ell -1

The region is dominated by the persistent East Pacific High, a nearly stationary
anticyclonic feature which is generally centered just off t1le coast. During
summer, with the midlatitude storm track far to the north, the position of the
anticyclone is,nearly invariant; winter months, however, see a southward migration
of the high, allowing cyclonic systems from the Pacific to enter. These storms
provide the study region with the major portion of its annual rain.

Because of topography and land-sea temperature differences (th6 latter
heightened by the cool temperature of the California Current), small-scale circu-
lation can differ significantly from regional patterns. Areas near the coast are
subject to a marked diurnal reversal which features daytime onshore (sea breeze) winds
and nighttime offshore (land breeze) winds. This sea-land regime is relatively
shallow; as a result, winds are often funneled through coastal valleys and canyons.
This effect is most pronounced in Ventura County, where several long, steep-walled
river valleys (notably the Ventura and Santa Clara River Valleys) penetrate to
interior basins, allowing coastal air p,arcels to travel many miles inland.

The typical shallowness of the marine layer near the coast is caused, in large
part, by temperature inversions, which are present in all seasons but are stronger
and more common in summer and-fall. 40/ Three basic types can be identified: marine
inversion, caused by cooling of low-@Tevel air passing over the cool ocean surface;
radiation inversions, caused by nocturnal cooling, which weaken or disappear during
warmer hours of the day; and, subsidence inversions, a result of large-scale descent
of air along the east side of the East Pacific High. 41/ As a result
of the inversions, upward air motion is inhibited, resulting in confi-nement of
low-level parcels to valleys and coastal plains below the level of surrounding
mountains. Severe or persistent periods of inversion entrapment combined with in-
adequate ventilation can result in heavy buildUD of atmospheric pollutants in the
region.

As mentioned earlier, precipitation in the study region falls chiefly in
winter months, with the major portion occurring between November and April, usually
in conjunction with mid-latitude synoptic-scale cyclonic storms. Summer thunder-
storms and tropical disturbances occasionally provide warm-season rainfall.

An additional feature which exerts a significant effect upon the study area
is the so-called Santa Ana condition, characterized by strong easterly winds
caused by a high pressure system located over the Plateau region of the western
United States. As a result of katabatic heating of the descending air near the
coast, the winds tend to be very warm and dry; in addition, channeling within the
valleys produces strong, gusty winds at many locations. Although such
winds tend.to advect pollutants onshore, resulting in relatively clean air near
the coast, weak Santa Anas.can transport air pollutants from the Los
Angeles basin, to the southeast, into the study region. Santa Ana conditions are
most common during fall and winter months, often preceding the passage of a mid-
latitude frontal system.

C L I M A T E

The Santa Barbara-Ventura area is characterized by a Mediterranean.
climate, with mild temperatures and predominantly winter precipitation, and cor-
responds to the Csb class of the Kbppen climatic classification system. 42/ Due
primarily to the marine influence, coastal areas undergo rather small.diurnal and

226

annual temperature variations; inland areas, on the other hand, experience larger
maximum-minimum differences. This coastal inland dichotomy results in the previ-
ously mentioned sea-land breeze wind regime-common to the region.

Inversion height is an important parameter influencing air pollution potential
(a measure of the trapping of pollutants near the surface). In general, lower in-
version heights produce higher concentrations by limiting the volume of air in
which pollutants are confined. Table 1 lists average monthly inversion
heights at Ventura airport in 1965; in most-cases, inversions were higher in after-
noon hours, although June and August figures showed a reversal.of this trend.

Solar radiation is another important factor which influences air pollution
levels. During winter, when-solar zenith angle (and, therefore, incoming radiation)
is lowest, inversions are less likely to "burn off" as a result of upward convection
of warm air near the surface, and may persist throughout the day. Primary pollu-
tants such as sulfur dioxide (S02), hydrogen sulfide (%), and carbon monoxide- (CO)
are likely to be highest during winter, when inversion eight is.generally lower
and persistence can be high. Photochemical reactions, however, typically proceed
over time scales measured in hours (depending on ultraviolet intensity). As a
re.sult, photochemically produced secondary pollutants (such as ozone) normally reach
maximum concentrations in summer month-s when solar radiation is greatest. Higher
summer surface temperatures give rise to a surface-based unstable layer which grows
vertically and.erodes the overlying inversion layer. This dilutes primary pollutant
concentrations between the.ground and the inversion base. 43/

TABLE 1:
AVERAGE INVERSION BASE HEIGHTS AT VENTURA AIRPORT, 1965 44/

MONTH TIME (PST) HEIGHT ABOVE MEAN SEA LEVEL

June 0300 762
1@00 610
July 0300 85
1500 299
August 0300 305
1500 259
September 0300 195
1500 521
October 0300 15
1500 132
November 0300 183
1500 348
December 0300 15
1500 317

E X I S T I N G E M I S S 1 0 N S

Surface emission fluxes used in the base-year ARTSIM*'runs were determined.,
according to four source, -types: -vehicular9 non-petroleum.stationary, petroleum.

*ARTSIM is ERT's air quality model and is described in ARTSIM BASELINE RUNS,, p. 236.
16-76658 2.27

onshore,znd.petroleum offshore. Using available emissi-ons inventories, traffic
'data, and petroleum production information, as well as pertinent emission.factors,
source fluxes were calculated for.each source type for I x I km UTM (Universal
Transverse Mercator system lines, as on USGS topographic maps) grid squares.
Finally, total flux for each square was determined by summing those from the four
source types.

Since surface wind data were obtained only for hourly interval.s, it was neces-
sary to interpolate-between successive hourly positions in order to-determine
,times of grid-square-boundary crossings. For simplicity, while the air parcel
center remained over a grid square, emissions from that square alone were used;
whenever the parcel crossed a boundary between squares, emissions were updated to
accommodate those-of the new square only, with emissions from the previous grid
sq.uare stopped. The times and positions of each boundary crossing were obtained
by assuming winds invariant for the duration-of the hour.

VEHICULAR EMISSIONS

Emission fluxes from the four classes of motor vehicles (cars, light-duty
trucksi heavy-duty gasoline powered vehicles, and heavy-duty diesel trucks) were
obtained from the headquarters and District 07 offices of.the California Depart-
ment of Transportation (CALTRANS). Using link-node information and@their
FREEWAY-11 program, CALTRANS was able to provide data on average daily emissions
per-UTM grid square for five pollutants:. total hydrocarbons (THC), reactive hydro-
carbons (RHC),..oxides of nitrogen (NOx), carbon-monoxide (CO), and sulfur dioxides
.(sox). By applying available diurnal'variation data (also obtained from CALTRANS),
Jt was possible to convert emissions from CALTRANS units (kg/day) to hourly totals
(kg/hr) in order to reflect time variations in traffic. Fluxes of NOx, RHC, and
CO were retained for ARTSIM input.

Vehicular mixes, representing-overall.averages for both freeway and surface
street travel, were;obtained from CALTRANS (Santa Barbara data) and the Ventura
.County APCD (Ventura data). Table 2 lists the respective vehicle distributions
.for-the two counties., weighted by total miles traveled.

TABLE 2:
MILEAGE-WEIGHTED VEHICLE MIXES'ASSUME-D FOR EMISSIONS CALCULATIONS
.(Percentage of Total Traffic)

VEHICLE TYPE SANTA BARBARA VENTURA

Light-duty autos .796 .811
Light duty trucks .130 .134
.Heavy-duty gasoline powered vehicles .067 .049
Heavy-duty diesel vehicles .008 .006

STATIONARY SOURCES

..Incl.uded in the cl-ass 2 source type are all stati-onary facilities except
.petroleum producti.on and processing facil-ities (thus, class 2 includes fugitive

.228

emissions from gasoline marketing operations). The emissions fluxes for the UTM
grid squares were furnished by the Ventura and Santa Barbara APCD offices. Since
available data provides only daily totals of emissions, it was necessary to divide
this latter figure by the number of daily hours of operation in order to estimate
emissions for a single hour.

OFFSHORE PETROLEUM FACILITIES

In general, class 3 comprises production platforms and tankers (the latter
in both loading/unloading and travel modes). Unfortunately, the emissions infor-
mation corresponding to such activity is rather sparse, and those data which are
available have been the subject of a great deal of controversy. During the course
of the current study, every-effort has been made to obtain as much emissions
information'as possible. Selection of factors for this study was made on the
basis of measurement method used, date of publication, and applicability to
petroleum facilities. These figures represent our current best estimates of local
petroleum-related offshore emissions.

PLATFORM EMISSIONS. During petroleum production, emissions of hydrocarbons
result f-rom evaporation of oil and gas, and from exhaust emissions of diesel
engines, gas turbines, and gas burners. 45/ Leach has presented a complete,
well-organized procedure for emissions e-stimation. 46/ His results, which fall be-
tween published high and low estimates, have been '@_tilized in Tables 3 and 4.
Table 3 lists these emission factors as functions of total oil/gas production. In
Table 4, average hourly emission rates (assuming 24-hour production) for the six
major primary pollutants are listed, according to oil and gas production rates.

Production rates for existing offshore platforms (for 1976) were obtained.from
Kinney and O'Neill..47/ By applying the emission rates in Table 4 to the pro-
duction figures, emi-ssions estimates for each existing Santa Barbara Channel plat-
form can be obtained.* Tables 5 and 6 list estimated production and emission rates
for oil and gas production, respectively, based on the emission factors in Table 4.

TANKER EMISSIONS. Emissions attributable to the transportation of crude
oil by barge or tankship are due primarily to two operations: combustion of fuels
while underway or in berth; and displacement of vapors during venting or purging.
In general, hydrocarbon losses tend to be largest during the latter operation,
and can contribute significantly to local and regional emissions totals. 48/

*The values in Table 3 represent aggregate emissions for the various source types
per unit -- 103 barrels -- of production.

229

TABLE 3:
EMISSION FACTORS Ob/103 barrels produced) FOR PETROLEUM PRODUCTION
EMISSION SOURCE TYPE THC RHC NOx CO S02 TSP

Diesel Engines 14.9 13.01 43.2 17.0 7.9 7.0
Wastewater Separation* 8.0 5.2 -- -- -- --
Turbine Compressors" -- -- 600.0 0.6
Pump Seals 74.0 48.0 -- --
Compressor Seals 4.0 2.6
Relief Valves 8.0 5.2
*Assumed to occur ogshore and thus not applied to platform emissions list.
"Emissions in lb/10 SCF gas burned.

TABLE 4:
EMISSION RATES (lb/hr) FOR OIL AND GAS PRODUCTION AND PROCESSING

OIL PROCESSING
POLLUTANT OIL PRODUCTION AND STORAGE GAS PRODUCTION, GAS PROCESSING
(per 103 B/D) (per 100 SCF/D)

THC 2.22 2.88 8.75
RHC 1.63 1.86 -- 2.80
NOx (as N02)* 0.9 1.8 2.1 6.10
CO .71 -- -- --
S5 .33 .44
TS .33 -- --

*From information provided by Laird. 49/

TABLE 5:
OIL PRODUCTION AND ESTIMATED EMISSION RATES FOR SANTA BARBARA CHANNEL PLATFORMS, 1976
PLATFORM TRACT OWNER PRODUCTION EMISSIONS (lb/hr)
(B/D) THC RHC NOX CO S02 TSP
Holly S. Ellwood ARCO 3,500 7.8 5.7 3.2 2.5 1.2 1.2
Hazel Summerland SOCAL 700 1.6 1.1 0.6 0.5 0.2 0.2
Hilda Summerland SOCAL 700 1.6 1.1 0.6 0.5 0.2 0.2
Heidi Carpinteria SOCAL 1,900 4.2 3.1 1.7 1.3 0.6 0.6
Hope Carpinteria SOCAL 1,900 4.2 3.1 1.7 1.3 0.6 0.6
Houchin Carpinteria Phillips 2,270 5.0 3.7 2.0 1.6 0.7 0.7
Hogan Carpinteria Phillips 2,270 5.0 3.7 2.0 1.6 0.7 0.7
Hillhouse Dos Cuadras Sun 10,400 213.1 17.0 9.4 7.4 3.4 3.4
A Dos Cuadras Union 13,550 30.1 22.1 12.2 9.6 4.5 4.5
B Dos Cuadras Union 13,550 30.1 22.1 12.2 9.6 4.5 4.5

230

TABLE 6:
GAS PRODUCTION AND ESTIMATED EMISSIONS FOR SANTA BARBARA CHANNEL PLATFORMS, 1976
PLATFORM PRODUCTION NOX EMISSIONS
(100 SCF/D) Ob/hr)
Holly S. Ellwood ARCO 0 0
Hazel Summerland SOCAL 1.7 3.6
Hilda Summerland SOCAL 1.7 3.6
Heidi Carpinteria SOCAL 2.3 4.8
Hope Carpinteria SOCAL 2.3 4.8
Houchin Carpinteria Phillips 1.2 2.5
Hogan Carpinteria Phillips 1.2 3.5
Hillhouse Dos Cuadras Sun 4.4 9.2
A Dos Cuadras Union 4.7 9.9
B Dos Cuadras Union 4.7 9.9

Fuel combustion emissions from tanker operations are dependent upon ship
size, loading/unloading rates, and number of hours of operation, and are much
greater (by about an order of magnitude) during transit than while loading.*
Leach, in his analysis of OCS Sale #35 impacts, has made the following
assumptions: average tanker size, 175,000 bbl. (25,000 DWT); vessel speed,
eight kts; sulfur content, 0.2% by weight. 50/ In his analysis, he uses EPA
emission factors. 51/ Table 7 lists emissioT-rates for the six major pollutants
using the above assumptions.

TABLE 7:
EXHAUST EMISSION RATES FOR 175,000 BARREL TANKERS ACCORDING TO THE CALCULATIONS
OF LEACH

EMISSION RATE Ob/hr)
POLLUTANT UNDERWAY IN BERTH

THC 7.2 .72
RHC 4.7 .47
NO 11.2 1.1
TSO 16.0 1.6
S02 14.2 1.7
CO 1.0

Tanker loading and unloading fugitive vapor emissions have been the subject of
intense controversy in recent years. Even today, no definitive, widely accepted

*While in berth and loading, the ship's engines are operated at about 10% of cruise
power to provide "hotel services." It is assumed that the pumping emissions associ-
ated with loadinq were qenerated at the marine terminal rather than on the vessel.

231

emission factors are in use. Leach proposed an emissions rate of 2.0 lbs
THC/103 gallons loaded, a compromise between several published figures. 52/
Laird prefers a lower value: 1.2 lbs THC/103 gallons. For our purposes, how-
ever, the data provided by MacKenzie and Rau are preferred, because of the
thoroughness of their study and recent date of publication. 53/ According to
that publication, loading emissions are functions of tank condition prior to
loading (see Table 8 below) and a load-generated component.

TABLE 8:
ARRIVAL HYDROCARBON CONCENTRATIONS

AVERAGE HC RANGE OF ARRIVAL
CARGO TANK ARRIVAL ARRIVAL CONCENTRATION CONCENTRATIONS
CONDITION CATEGORY (% BY VOLUME) (% BY VOLUME)
CLEANED 2.5 0 - 5.0
DI RTY BALLASTED 5.0 2.0 - 8.0
EMPTY & UNDISTU .RBED 8.0 2.5 -13.5

Total loading emissions can be determined according to
E = C-V + P-A-(G-U)
100
where E = Total vol ume of HC emitted (ft3)
C = HC arrival concentration (@able 8)
V = Volume of cargo loaded (ft )
P = True vapor pressure (TVP) (psia)
A = Surface area of cargo (ft2j 2
G = HC generation coefficient = 0.36 ft3@psia-ft
U = Final ullage correction (ft3/psia-ft )
and where the two right-hand-side terms correspond to arrival and load-generated
components, respectively.

Since emission rates decrease with increasing anker size, we assume a 70,000 DWT
tanker (expected to be an upper bound for local tan*kships and thus a conservative
figure), TVP of 6 psia, based on estimated Reid vapor pressure of 7.0 psia and
crude oil temperature of 800F, and tank conditions 45% cleaned, 10% ballasted,
45% empty and undisturbed (figures provided by MacKenzie and Rau as typicil of a
vessel of such size). The result is an emission factor of 1.9 lbs THC/10 gal
loaded -_ 1.2 lbs from arrival HC + 0.7 lbs generated component. This value, which
closely approximates Leach's, falls nearly midway between those of Laird
and EPA, and is far lower than API estimates rep@rted by MacKenzie and Rau
(the latter two rates are 2.7 and 4.6 lbs THC/10 gal, respectively).
Reactivity of the fugitive HC generated during tanker loading (and later, in
assessing spill impacts) was assumed to be .30. Most of the HC emitted in such
situations belongs to the alkane class of compounds. The reactions involving
alkanes (or olefins, an important constituent of auto exhaust) take place more

232

slowly. In the current study, this difference in ozone formation.potential was
modeled by assuming much lower reactivity values for alkanes.

Estimates of the daily throughput, storage, capacityl, and pumping rate of--
local marine terminals were obtained from Lind. 54/ Using these--figures and-the
above emission factors for tanker loading, it-was possible toicalculate-emission.
rates for.each facility. In additi-on, fugitive emissioSs fr 'om storage tanks
were estimated using Leach's-55/ figure of .05 lb/hr/10 bbl stored.* Table 9
lists-pumping rates and storage capacities as well as computed emission rates
for both existing andpossible future terminal sites, assuming maximum pumping
and storage.

TABLE 9:
YUMPING RATES, STORAGE.CAPACITY@, AND HC EMISSIONS FOR LOCAL MARINE TERMINALS

PUMPING
LOADING EMISSIONS..-STORAGE EMISSIONS
RATE STORAGE (lb/hr)** (lb/hr)***
TERMINAL (bbl/hour) (bb,l) THC RHC THC RHC

EXISTING

Ml Union/Cojo 3,250 55,000 259.4 77.8 4.9 1.5
M2 GETTY/Gaviota 9,000 275,000 718.2 215.5 24.3 7.3
M3 AMINOIL/Ellwood 5,000 160,000 399.0 119.7 14.1 4.2
M4 SOCAL/Carpinteria 12,000 268,600 957.6 287.'3 23.6 7.1
M5 GETTY/Ventura 10,000 320,000 798.0 239.4 28.2 8.5
M6 UNION/Ventura 10,000 273,000 798.0 239.4 24.1 7.2
M7 EDISON/Mandalay 11,875 315,000 949.6 284.9 27.8 8.3

POSSIBLE FUTURE SITES -

M8 EXXON/Los Flores 13,000 440,000 1995.0 598.5 38.8. 11.6
to 26,000
M9 17,500 338,000 1396.5 419.0 29.8 8.9
M10 20,000 1,000,000 1596.0 478.8 88.2 26.5'

"Emissions generated while loading is occurring, assuming ten-hour loading time.
***Representing average hourly values (assumed steady over 24-hour period).

ONSHORE PETROLEUM FACILITIES

Emissions data for onshore petroleum production, handling, and processing
facilities were obtained from the Santa Barbara and Ventura County APCD emissions
inventories. Figures obtained were based on,either actual measurement or-orl cal-
culations from relevant emission factors.

*Assuming floating roof tanks with conditions representing average of "new tank"
and "old tank" characteristics.

233

It is expected th.at increases in offshore oil production will cause sizable
growth of the th.roughput of onshore treatment and separation (T & S) facilities;
in addition, the number of such.facilities along the coast may increase signifi-
cantly. Table 10 lists T & S throughputs for those facilities known to be in
operation in 1976. 56/ In Table 11, estimated T & S emissions in 1976, computed
by applying emissi6n-factors in Table 4 to the throughputs in Table 9, are
presented. Expected future trends will be discussed in a later section of this
report.

TABLE 10:
ESTIMATED THROUGHPUTS OF EXISTING TREATMENT AND SEPARATION FACILITIES,
SANTA BARBARA VENTURA COAST, 1976
LOCATION. OWNER OIL (B/D) THROUGHPUTS GAS (MCF/b)
Gaviota ARCO 80 195
Molino Shell 2,000
Tajiguas Phillips 0 4,000
Ellwood AMINOIL 100 500
Ellwood ARCO 3,500 0
Carpinteria SOCAL 4,460 7,920
La Conchita Phillips 4,540 2,270
Rincon ARCO 700 100
Rincon Mobil 34,500 11,300
Rincon Norris 500
Seacliff Chanslor 2,600 13,700

TABLE 11:
ESTIMATED-EMISSIONS FROM TREATMENT AND SEPARATION FACILITIES, 1976
LOCATION OWNER EMISSIONS (lb/hr)
THC RHC NOX S02
Gaviota ARCO .23 .15 .15
Molino Shell 12.96 8.37 8.10
Tajiguas Phillips 39.40 12.60 27.45 1.98
Ellwood AMINOIL .29 .10 .18
Ellwood ARCO 10.08 6.51 6.30
Carpinteria SOCAL 82.14 33.06 56.34 3.48
La Conchita Phillips 32.94 14.80 22.02 1.00
Rincon ARCO . 2.88 1.86 1.80
Rincon Mobil 148.24 95.81 131.03 4.97
Rincon Norris 1.44 .93 .90
Seacliff Chanslor 142.44 48.00 98.70 6.78

234

OIL AND GAS DEVELOPMENT SCENARIOS

O'Neill has published a set of production scenarios representing various
levels of Santa Barbara Channel oil and gas production. 57/ The three cases
outlined represent low, middle, and high estimates of fuT-ure production and
were adopted in order to reduce the.-rather large number of possible production
levels into*a small, yet meaningful,,set of combinations.

O'Neill's Case 1 (low estimate) scenario.assumes that future production is
restricted to platforms now in-place -- Dos Cuadras, Carpinteria, Summerland,
SoUth Ellwood, and Hondo. Production would peak in 1980.with 65,700 B/D and
49 MM SCF/D gas.

Case 2 represents a mid-range estimate for future Channel development. In
formulating this alternative, O.'Nei.11 assumed new platforms in Dos Cuadras, Car-
pinteria, Hueneme, Santa-C-lara (three platforms, Northern field)i and Santa Ynez
.(ful-l development, Exxon.estimate of 423 million barrels recovery) OCS tracts,
increased production at Conception, Summerland; and Carpinteria tideland tracts,
and 17 new wells drilled at Holly (but denial of permission to ARCO to expand
its onshore processing facilities). Peak development, which would occur in 1985,
would total 165,300 B/D oil and 134 MM SCF/D gas.

The third and final production scenario-represents an expected upper bound
for future Channel production.. Case 3 is similar to Case 2. except that Santa Ynez
production assumes.the USGS recovery estimate of 730 million barrels of oil (30-year
production time), that the Southern. field in the Santa Clara unit is brought into
production, that Pitas Point production takes place, and that ARCO is allowed to.expand
its South Ellwood onshore facility.and install a Stretford unit to clean its pro-
duced gas. Peak-developmentJor this scenario would occur in 1988 and total 350,000
,B/D oil and 253.3 MM SCF/D gas.

Table 12 is a list of future oil and gas production estimates for the Santa
Barbara Channel,using O'Neill'-s Cases 1, 2, and 3 scenarios with the assumptions
listed above.

TABLE 12:
ESTIMATED FUTURE OIL AND GAS PRODUCTION, SANTA BARBARA CHANNEL

1976 1980 1983 IM5 1987 1989 1991

CASE 1 (LOW ESTIMATE) -
Oil (10,000 B/D) 48.3 65.7 44.1 37.1 31.5 26.7 22.3
.Gas (lU,000,000 SCF/D) 31.0 49.0 29.0 25.0 21.0 18.0 15.0

CASE 2 (MID-RANGE ESTIMATE)
Oil (10,OuO B/D) 48.3 120.1 153.5 165.3 139.5 132.5 107.4
'Gas (10,000,000 SCF/D) 31.0 @72.0 118.0 134.0 113.0 107.0 89.0

CASE 3 (HIGH ESTIMATE)
Oil @(10,000 B/D) 48.3 101.3 202.1 269.9 336.6 315.0 255.2
'Gas-(10,000,000 SCF/D). 31.0 46.4 129.7 206.0 237.0 228.0 184.5

235

ARTSIM BASELINE RUNS
Preliminary tasks involved in the air quality impact simulations included
selection of the days and trajectories to be modeledi acquisition and processing
of meteorological, air quality, and emissions data, and calibration of the model
runs in order to equate ARTSIM pollutant concentrations -with those observed at
the respective air monitoring locations. Sampling days were selected from among--
both high-oxidant and average days; each oxidant monitoring station in the study
area was,used as a receptor location for at least one case; and, trajectories were
selected in order to@model the onshore impact of every Santa Barbara Channel
offshore lease unit.

Upon completion of the base year calibration runs, in which initial pollutant
concentrations were varied within reasonable bounds until satisfactory correspon-
dence with observed levels was obtained, future year trajectories were modeled
using the same air parcel path but different'emissions and initial concentrations
using projected population and emission factor information. The latter simulations.
became the basis for the OCS impact runs (see ARTSIM OCS IMPACT SIMULATION RUNS)..

D E S C R I P T 1 0 N 0 F T H E M 0 D E L

The ARTSIM (Atmospheric React-icn and Transport SIMulation) model was
developed by ERT as a predictTive tool for aiding decisionmakers in assessing
regional and local air pollution impacts. A successor to ERT's well known DIFKIN
model, a pioneer.in the field of reactive pollutant modeling, ARTSIM can be used
to predict the behavior.of pollutants emitted from distributed sources (such. as
transportation networks and residential areas) as well as concentrated industrial
sources. In essence, ARTSIM computes the time-dependent behavior of a moving air
parcel in which a multicomponent gaseous mixture undergoes simultaneous diffusion
and chemical reactions.

ARTSIM is a semi-Laorangian model in which the air parcel carries its own set
of coordinates in a trajectory aligned with the mean wind direction and traveling
at the prevailing horizontal wind velocity. The basic.ARTSIM equation sets the time
rate of change of concentration equal to a diffusion term and a reaction term.
Numerical integration of this equation, subject to meteorological and chemica.1
conditions, yields concentrations of each pollutant as a function of height and
time. The boundary conditions at the surface set the emission level of pollutants;
in addition, emissions can be introduced at some specified above-ground elevation.

A simplified flow chart of ARTSIM input, processing, and output appears in
Figure 2. Input parameters specified by the user include meteorological conditions
(vertical eddy diffusivities, mixing height, and winds), pollutant,data (initial
concentrations and surface emissions), and ultraviolet intensity; chemical rate
constants, unless specified, revert to default values within the program. Output
consists of concentration of each of the species at up to ten user-specified
vertical points at specified time intervals along the trajectory path.

In the current study, 16 reactions involving ten species were modeled in
cells bounded at 0, 100, 200, 300, and 400 m above the surface. Species for
which concentrations were calculated are.nitric oxide (NO), reactive hydrocarbons.
(HC), nitrogen dioxide (NO@), ozone (03), nitrous acidz(HN02), nitrogen trioxide
(N03), nitrogen pentoxide N 05), hydroxyl (OH), oxidi ed hydrocarbon radicals (R02),
and carbon monoxide,(CO). Re 16 reactions included in the chemical module are:

236

1 PKOTON+NO2 -----s--NO+O3
2. NO+03 -N02+02
3. O+HC 8RO2
4. OH+HC -e-8RO2
5. R02+N0 W-N02+ .1250H
6. RU2+NO2 PAN
7. OH+NO -_-HN02
8. OH+NO2 __-HN03
9- 03+HC do. RO 2
10. PHuTON+HN02----*-OR+NO
11. NO +0
2 3 R'03+02
12. N03+NO2
13. N205 N03+NO2
14. N205+H20 ------- 214NO3
15. NU+NO2+H2O - 2HN02
16. N02+Particles -e-Products

At present, the AHTSIM chemical module is being expanded significantly to update
the HC/NO mechanism and to include sulfur chemistry. Since validation studies
have not yet been completed, however, the simpler 16-reaction module was used in
.the current project.

The ARTSIM trajectory section is driven by a supplementary program which
interpolates available surface wind data by means of a weighting factor (which
weighted winds at each station inversely with distance from the air parcel).
Wind data are generally reported hourly; thus, it is necessary to assume winds to
be invariant through each one-hour period. Although trajectories over the ocean
or homogeneous land surfaces need no further processing, those which cross complex
terrain (e.g., mountain-valley areas) occasionally require modification: it is
sometimes necessary to alter the path to account for low-level channeling of flow
within valleys or around hilly areas.
Vertical eddy diffusivities (Kz) are specified at the top and bottom of the
parcel and midway between those levels for which concentrations are calculated;
in our case, Kz parameters were listed at 0, 50, 150, 250, 350, and 400 meters
,above the surface, and updated hourly. The diffusivities were obtained by using
rawinsonde data and a computation method based on vertical thermal structure
(lapse rate) and wind shear (see Appendix I for description of this method).
@Chemical rate constInts are specified in units of min-' for first-order
reactions and ppm-1 min- for second-order reactions. Values can be inserted by
the user; otherwise, the existing default constants are utilized. Photodissoci-
ation rate values, however, are time-dependent (proportional to solar zenith angle);
currently in use at ERT is an EPA program which determines these values as
functions of latitude, longitude, day of year, and time of day, updating them every
ten minutes. 58/

237

COMPUTATIONAL
INPUTS MODULES

Diffusivities Meteorological
Module OUTPUT

Winds
A. Species Concentration

as a Function of

Initial Concentrations Hei-ght and Time
Boundary Conditions Chemical

Module
Ultraviolet
Intensity

Figure 2 ARTSIM Flow Diagram

238

Emission fluxes from the surface, or elevated sources, are obtained from
inventories and calculated either internally or externally (in our case, the
latter, again for reasons of cost). For use in ARTSIM, units must be converted
from the standard mass/time to meters/minute in order to obtain flux velocities.
The flux terms represent boundary conditions at the bottom of the vertical mesh;
the upper boundary condition (at 4UO m, the top of the cell) is zero pollutant
flux.

Initial pollutant concentrations comprise the final input parameters required
by ARTSIM. Values of NO, HC, N02, 039 HN02. and CLI are specified at the five
vertical levels as initial conditions; concentrations of the rem 'aining four pol-
lutants (N03 N 05, OH, and R02) are computed based on known chemical relationships
using conceniraiions of the first six substances. Initial conditions are subject
to more uncertainty than the other input parameters since most trajectories origi-
nated over the ocean, where air quality data are nonexistent. However, by assuming
certain initial pollutant ratios (e.g., HC (ppm):NOx (ppm)=5:2 and N02:NO-!:2:1)
and varying the initial levels to allow ARTSIM predictions to match observed air
quality data later in the day, adequate results were obtained. 59/

B A S E Y E A R C A L I B R A T 1 0 N R U N S

Selection of modeling days and trajectories for the simulation study was
done on the basis of oxidant concentration, predominantly high-oxi.dant days with
some typical or average cases, ana trajectory path, to evaluate impacts of each
lease tract and to include every air monitoring station as a receptor. Meteor-
ological data (surface winds, upper air soundings), surface emission fluxes, and
ultraviolet intensity were determined for the individual simulation days and put
into ARTSIM. Initial pollutant concentrations, the only remaining ARTSIM data
requirement, could not be determined precisely since all parcel paths began
over the Channel; as a result, it was necessary to estimate the initial conditions
on the basis of onshore data, varying the levels of the respective pollutants
until satisfactory correlation with air quality measurements was obtained when
the parcel reached the receptor later in the day.

As mentioned above in the description of the model, the trajectory-generation
program used in the current study utilized surface wind observations from one or
more stations to determine the position of the parcel every hour. Since nearly
all wind data are.in the form of hourly averages or hourly observations, winds
must be assumed invariant through each one-hour period. Distance of the parcel
from each wind station is determined for every hourly location; the subsequent
calculation.of parcel movement utilizes a weighting factor proportional to the
inverse of the distance from parcel to wind station (e.g., wind vectors for a
station one km from the parcel would be weighted twice as heavily as those for
a station two km away). In certain instances, it was deemed necessary to modify
the trajectories somewhat in order to account for terrain influences: trajec-
tories reaching such inland stations as Ojai, Simi, and Santa Paula, for example,
were altered by assuming low-level winds to be channeled through valleys or
canyons, rather than directly over,high terrain. Coastal area station trajec-
tories, however, needed no such modification.

Trajectories were calculated to correspond to various arrival times during
the day. Selection of a single case was based on two considerations: oxidant
concentration (peaK or near-peak preferred) and lease tracts traversed. Table
13 lists the simulation days, arrival times, and station locations selected for

239

the current study, and includes ozone concentrations for each station at the
arrival time.

TABLE 13:
DAYS, ARRIVAL LOCATIuNS AND TIMES, AND OBSERVED OZONE uONCENTRATIONS FOR
THE TRAJECTORIES SELECTED FOR USE IN THIS STUDY

ARRIVAL ARRIVAL
DATE LOCATION TIME (PST) CONCENTRATION UPON ARRIVAL (pphm)

7/18/74 Fairview 1400 16
(SBCo)
7/18/74 State St. 1400 18
(SBCo)
5/l/75 Cathedral Oaks 1300 10
(SBCo)
7/9/75 Camarillo 1400 9
(VCo)
7/lO./75 Simi Valley 1400 19
(VCo)
7/10/75 Ojai 1300 19
(VCo)
9/2b/75 Santa Paula 1300 12
(vco)
9/25/75 Ventura 1400 16
(VCo)

F U T U R E Y E A R B A S E L I N E R U N S

Selection of the future years for ARTSIM modeling was based upon the paths
of individual trajectories: the year of expected peak production for the particu-
lar tract or facility traversed was chosen in order to simulate maximum expected
emissions. Petroleum facility emission fluxes were obtained by applying previously
discussed emission factors to future production estimates. 60/ Non-petroleum
emissions and initial pollutant concentrations were determiTed by applying future
population and vehicle emission factor projections (see below).

VEHICLE EMISSIONS

Nordsieck has estimated vehicle emissions for future years by applying
EPA future emission factors to projected daily vehicle miles (DVM) for the Santa
Barbara South Coast. 61/ Vehicle mixes listed in EXISTING EMISSIONS were
assumed constant for Tu-ture years. Table 14 lists Nordsieck's future
estimates of RHC, NOX9 and CO, as well as ratios of current-to-future emissions.
The latter ratios were applie 'd to CALTRANS figures (see EXISTING EMISSIONS)
to obtain future vehicle emissions by UTM square, which were in turn used for
ARTSIM modeling. Emissions for peak years not shown in Table 14 were acquired
by interpolating between listed values.

240

TABLE, 14:
FUTURE VEHICLE@EMISSIONS ESTIMATES FOR SANTA BARBARA COUNTY SOUTH COAST (tons/day)

SANTVBARBARA COUNTY @1973 1977 1980 1985 1990 1995

RHC EIMISSIONS 9.69 7.40 5.45 2.84 .2.12 2.08
.RATI'O TO 1976 EMISSIONS "1.22. .93 .68 .36 .27 .26
NOx EMISSIONS 16.3 16.1 13.6 11.2 1.1.2 11.7
RATIO@70 1976 EMISSIONS 1.01 1.0 .84 .69 .69 .72
.CO-EMISSIONS 110.4 81.1 59.6 @41.2 38.1 39.3
RATIO TO 1976 EMISSIONS 1.25 .92 .67 .47 .43 .44

TABLE 15:
FUTURE VEHICLE EMISSIONS ESTIMATES FOR-VENTURA COUNTY,(tons/day) 62/

VENTURA COUNTY 1973 1.977 1980 1985 11990

.RHC EMISSIONS 4.72 2.19 2.20 2.10 2.10 2.10
'RATIO TO 1:976 EMISSIONS 1.65 @.78 .79 ..75 .75 .75
NOx EMISSIONS 2.12 2.09 2.33 2.58 2.56 @2.52
RATIO TO -1976-EMISSIONS 1.01 -1.00 1.11 1.23 1.22 1.20
CO EMISSIONS 6.62 7.00 7.16 6.21 6.44 6.70
RATIO TO 1976 EMISSIONS .96 1.01 1.04 .90 .93 .,97

OTHER'NON-PETROLEUM -INDUSTRIES

Emissions from aircraft and,non-petroleum stationary sources were also obtained
from Nordsieck. Table 16 lists:Projected RHC. NOx. and CO values. As in the
previous case, emissions for years not listed were obtained by interpolating the
values in the table.

TABLE 16:
FUTURE AIRCRAFT AND STATIONARY SOURCE--(NON-.;PETROLEUM) EMISSIONS FOR
SANTA BARBARA COUNTY SOUTH COAST@(tons/day) @3/

SANTA.BARBARA'COUNTY 1973 1977 1980 1985 .1990 1995
RHC EMISSIONS :4.72 .,2.19 2.20 2.10 2. 10 2.10
RATIO TO 1976 EMISSIONS 1 65 .78 .79 .75 .75 .75
2 09
NO EMISSIONS 2.12 2.33 2.58 .2.56 2.52
@ATIO TO 1976 EMISSIONS 1 01 1.00 .1.11 1.23 1.22 .1.20
7.00
CO EMISSIONS 6.62 1.01 6.21 6.44 6.70
,RATIO TO'1976 EMISSIONS .96 1.04 .90 .93 .97

241

Ventura County estimates based on values obtained from Schere are shown
in Table 17.

TABLE 17:
FUTURE AIRCRAFT AND STATIONARY SOURCE (NON-PETROLEUM) EMISSIONS ESTIMATES FOR
VENTURA COUNTY (tons/day) @4/

VENTURA COUNTY 1973 1977 1980 .1985 1990 1995

RHC EMISSIONS 12.35 6.55 6.96 7.21 7.62 8.04
RATIO TO 1976 EMISSIONS 1.49 .79 .84 .87 .92 .97
NO EMISSIuNS 25.82 28.66 33.48 40.29 42.56 43.98
@ATIO to 1976 EMISSIONS .91 1.01 1.18 1.42 1.50 1.55
CO EMISSIONS 123.43 144-71 157.48 147.55 161.74 178.76
RATIO TO 1976 EMISSIONS .87 1.02 1.11 1.04 1.14 1.26

PETROLEUM INDUSTRY-EMISSIONS

Emis'sion factors for petroleum production, processing, and transport were
obtained from Leach, as outlined in EXISTING EMISSIONS, and were ap-
plied to future productio *n estimates (see OIL AND GAS DEVELOPMENT SCENARIOS)
in order to estimate total emissions within the study area. For the baseline situation,
Case I development (existing facilities only) was assumed. Table 18 lists production
and emissions estimates for selected future years, while Table 19 shows total study
area emissions for the same years.

TABLE 18:
EMISSIONS FROM PETROLEUM PRODUCTION, PROCESSING, AND TRANSPORT FOR SANTA BARBARA-
VENTURA STUDY AREAS (tons/day) -- CASE 1 DEVELOPMENT (EXISTING FACILITIES)

SANTA BARBARA-VENTURA 1976 1980 1985 1990 1995

OIL PRODUCTION
(10,000 B/D) 48.3 65.7 37.1 24.5 16.3
GAS PRODUCTION
(10,000,000 SCF/D) 31.0 49.0 25.0 16.3 10.8
EMISSIONS
RHC 1.20 1.65 .93 .67 .44
NOX .34 .47 .26 .19 .13
CO .14 .18 .10 .08 .05

242

TABLE 19:
TOTAL STUDY AREA EMISSIONS, FUTURE YEARS (tons/day) -- CASE 1 DEVELOPMENT
(EXISTING FACILITIES)

TOTAL STUDY.AREA 1976 1980 1985 1990 1995

RHC 55.8 42.4 28-0 24.2- 24.7
NOX 86.2 85.2 85.8 89.9 94.9
Co 434.3 366.4 291.7 310.9 338.2

ARTSIM OCS IMPACT SIMULATION RUNS'

In order to. assess potential impacts of future Santa Barbara Channel petroleum
production and handling upon.the air quality of the study-region, two alternative
.simulation techniques were empl9yed in'determining ARTSIM input parameters. The
first approach, modeling of the influences of petroleum facility emissions upon
ambient levels of the precursors (NO and RHC) and thence upon oxidant concentra-
x
tion, consisted of-varying the initial pollutant concentrations in proportion to
regional emissions. Surface emissions fluxes were held constant in order to isolate
the ambient air quality impact of variations in initial conditions alone. The
second technique was designed to model potential impacts of,individual.point,sources
(platforms,, T & S facilities, marine terminals) at certain onshore receptor locations.
Future baseline runs and O'Neill's Cases 1. 2, and 3 production scenarios formed the
basis for the,simulations.

0 X I D A N T V A R I A T 1 0 N Q U E T 0 C H A N G E S I N A M B I E.N T
P R E C U R SO R C 0 N C E N T R A-T 1 0 N S

As outlined in DESCRIPTION OF THE MODEL. oxidant (oz one) buildup in
the chemical module of the ARTSIM program results from.the i 'nteraction of-several
precursor species: RHC and NOX9 in particular, are generally thought of as ozone
producers, with NO, N02, and 03 in a dynamic equilibrium described by reactions I
and 2 in the chemical scheme outlined in ARTSIM BASELINE RUNS. In addition,
the ratios of initial concentrations of RHC:NOx and N02:N0 heavily influence peak
ozone levels. Local monitoring data were used in estimating the above concentrations
and ratios for use in baseline and subsequent ARTSIM runs. These values were then
modified by incorporating-emissions for the three petroleum development scen-arios to
obtain three sets of initial concentration..conditions. By making ARTSIM runs in
which only these initial pollutant levels were varied, the,impact of petrole@um
facility@emissions upon background precursor levels,-and,thus. upon oxidant forma-
tion, was assessed.

Table 20 lists forecast values of emissions (tons/day) from petroleum facili-
ties in the Santa Barbara Channel and adjacent shoreline:for the three development
scenarios outli-ned earlier, using emission factors also listed earlier in this
chapter. Table 21 lists emissions from petroleum facilities as,percentages.of total
study area emissions for the examples in Table 20.- Case I development,(current -
facilities only) constitutes the baseline emissions case: scaled.future year-initial
conditions were allocated to petroleum-facility and non-petroleufti.components accorda-
ing to the percentages listed in Table 21. Initial conditions for-the [email protected]

17-76658 243

scenarios were obtained by adding this non-petroleum component to the respective
petroleum-facility emissions listed in Table 20.

TABLE-20:
ESTIMATED EMISSIONS DUE TO PETROLEUM FACILITIES WITHIN.THE STUDY AREA (tons/day)

1976 1980 1985 1990 1995

CASE I DEVELOPME.NT
RHC 1.20 1.65 .93 .67 .44
NOX .34 .47 .26 .10
CO .14 .18 .10 .08 ..05
CASE 2 DEVELOPMENT
RHC 1.20 2.97 4.19 3.10 1.58
NOx .34 .85 1.18 .88 .45
CO .14 .34 .46 .34 .17
CASE 3 DEVELOPMENT
RHC 1.20 3.43 6.80 9.63 2.40
NOX .34 .98 1.93 2.74 .68
CO .14 .39 .76 1.08 .27

TABLE 21:
PERCENTAGES OF TOTAL STUDY AREA EMISSIONS RESULTING FROM OFFSHORE AND
COASTAL PETROLEUM FACILITIES

1980 1985 1990 1995

CASE I DEVELOPMENT
RHC 2.2 3.9 3.3 2.8 1.8
- NOX .39 .55 .30 .21 .14
CO 1.03 .05 .03 .02 .01
CASE2 DEVELOPMENT
RHC 2.2 7.0 1.5.0 12.8 6.1
NOX .39 1.0 1.4 1.0 .47
CO .03 .09 .16 .11 o5
CASE 3.DEVELOPMENT
RHC .2.2 8.1 24.3 39.8 9.0
NOX .39 1A 2.2 3.0 0.7
CO .03 .11 .26 .35

To demonstrate the above technique by-way of example, let us examine an impact
.simulation for the trajectory of May 1,1975, which arri-ved at the Cathe.dral'Oaks
.(Santa Barbara) monitoring-station at 1300 PST. The trajectory originated over the
ocean west of.Santa Barbara (the simulation run began.at 0700) and passed over the
Hondo site in.the Santa-Ynez tract about 1100 PST. This sample day represented a
moderate ozone day, with peak.ozone of 9 pphm.occurring-at the time of arrival of the
air.parcel; this can be,considered an average2summer@ozone day for the Santa Barbara
area. Initial concentrations,RHC,,N02,'and.-NO obtained'duri:ng calibration exercises
appear in Table 22.

244

TABLE 22:
INITIAL POLLUTANT CONCENTRATIONS FOR CALIBRATION RUNS, 5/l/75 (see text)

HEIGHT ABOVE SURFACE POLLUTANT CONCENTRATIONS (pphm)
RHC N02 NO

0 4.0 3.0 1.8
100 3.5 2.6 1.6
200 2.5 1.9 1.1
30U 2.0 1.5 0.9
400 1.5 1.1 0.7

1985 was selected as the future year for modeling purposes since it represented
the peak production year for both the middle (Case 2) production scenario and the
Santa Ynez lease tract. In comparing total 1985 study area emissions for the three
development cases, Ventura County emissions were neglected owing to the large distance
between the trajectory origin and Ventura. Surface initial pollutant concentrations
of RHC, N02, NO, and 03 for Cases 1, 2, and 3 are listed in Table 23: separate
ARTSIM runs were made using the three sets of initial concentrations, and holding
all other input variables (surface emissions, meteorology, sunlight) constant. The
results, shown graphically in Figure 3, indicate a range in peak 03 from 5.0 pphm
(Case 1) to 10.5 (Case 3); the Case 2 peak (8.8 pphm) was very close to the 1975
calibration value of 9 pphm.

For the purposes of modeling initial condition impact upon Ventura County, a
trajectory of September 25, 1975, arriving at the City of Ventura at 1400 PST was
chosen. Peak ozone on that day was higher at the Ventura station, which lies only
a few miles from the shoreline, than at locations further inland, an indication
that morning precursors exerted a major effect upon oxidant. If onshore surface
emissions for the same day were a major O@-producing'factor, inland 03 would be
expected to be higher than at Ventura -- in fact, this latter condition is the
normal summer situation in the area. Unlike the Santa Barbara run, non-petroleum
emissions from both counties were used for comparison purposes: since typical
gradient-level winds are northwesterly in the study area (i.e., directed from Santa
Barbara toward Ventura), it follows that transport of Santa Barbara emissions to
Ventura County is more common than the reverse.

TABLE 23:
INITIAL SURFACE-LEVEL POLLUTANT CONCENTRATIONS FOR 1985 SIMULATION RUNS --
TRAJECTORY OF 5/l/75

DEVELOPMENT CASE POLLUTANT CONCENTRATIONS (pphm)
RHC N02 NO 03

CASE 1 (EXISTING) 1.54 2.10 1.26 1.70
CASE 2 (MID-RANGE) 3.02@ 2.26 1.36 1.70
CASE 3 (HIGH) 3.78 2.37 1.43 1.70

245

(10.5 pphm)
10. Case 3

(8.8 pphm)
Case 2

0
,rq (5.0 pphm";
5 Case 1

0
Case I Existing Facilit;-s Only
0 Case 2: Moderate Development Scenarios
Case 3: High Development Scenarios

0
0700 0800 0900 1000 1100 1200 13@O
LOCAL TIME
Figure 3 Ozone Concentration vs. Time for Varying Initial Conditions.
Trajectory of 5/1/75, Using Scaled Initial Conditions an@i
Surface Emissions for 1985, (S;nta Barbara Mode rate-O3 Case).

Initial pollutant concentrations obtained from the calibration exercise
(in which peak 03 was 16.6 pphm) appear in Table 24.

TABLE 24:
INITIAL CONCENTRATIONS OF RHC, N02, and NO FOR VENTURA CALIBRATION RUN,
9/25/75 TRAJECTORY

HEIGHT ABOVE SURFACE (m.) POLLUTANT CONCENTRATION (pphm)
RH G N02 NO

0 6.5 3.0 1 5
100 5.5 2.5 1 3
20U 5.0 2.3 1 2
300 5.0 2.3 1.2
400 4.0 1.8

1985 was again selected as the future modeling year for the simulations; surface
initial concentrations of RHC, N02, NO, and 03 are listed in Table 25.

TABLE 25:
SURFACE-LEVEL INITIAL CONCENTRATIONS OF RHC, N02, NO, AND 03 FOR
1985 IMPACT SIMULATION, VENTURA (units pphm)
DEVELOPMENT RHC N02 NO 03
CASE 1 (EXISTING) 4.6 2.2 1..l 2.1
CASE 2 (MID-RANGE) 5.2 2.4 1.2 2.1
CASE 3 (HIGH) 5.8 2.5 1.3 2.1

Results of the three ARTSIM runs, in which only initial concentrations were varied,
are presented in Figure 4. Differences in magnitude of peak ozone between the
three development cases were less than for the Santa Barbara case discussed earlier,
since non-petroleum emissions were higher for the latter case, differences between
Cases 1, 2, and 3 petroleum emissions constituted smaller percentages of total
study area emissions, nevertheless, Case 1 and Case 3 peak 03 differed by about
3 pphm (14.9 versus 17.8); the Case 2 peak was 16.9 pphm.

Additional simulation runs were made to reflect two additional oxidant day
types: a high oxidant day for Santa Barbara and an average oxidant day for Ventura.
In. the former case, a trajectory arriving at the State St. ARB station on July 18,
1974, was selected (corrected peak hourly average ozone on that day was 18 pphm).
The latter situation was modeled using the trajectory of July 9, 1975, which arrived
at Camarillo at 1400 PST (peak hourly average 03, 9 pphm). Methodologies for both
runs were the same as those outlined above for the previous simulations. Results
for Cases 1, 2, and 3 initial conditions appear in Figures 5 and 6 respectively,
while plots of the four trajectories are shown in Figure 7. Table 26 lists Cases
1, 2, and 3 results for the four sampling days.

247

Case-3
Case 2 (16.9 pphm)

is. Casel .(14.9 pphm)

Case 1: Existing facilities only
P
0 oderate devclOPment scenario
-01 U C Case 2: MI
00 a.
0 Case 3: High devoloPMent scenario
U

rZ
0

01
0700 0800 0900 1600 lY00 li00 1300 14bo-
LOCAL TRE
Figure 4 Ozone Concentration vs. Time for Varying Initial Condition Trajectory
of 9/25/75, Using Scaled Initial Conditions and Surface Emissions for
1985 (No Petroleum Facility Fluxes) -- (Ventura 0- Case)

(2 2. 1 pphm)

Case 2
.(17.7 pphm)

Case 1
(9. 8 pphm)

0
0700 0300 0900 .1000 1100 1200 1300 1400

LOCAL TIMEE

.Figure 5 Ozone Concentration vs. Time for Varying Initial Concentrations
Calibration: 7/18/74 Sztati.-r.: State St. Arrival: 1400
Future Year Modeled: 1985--(Santa Barbara Hi7h-07 Case)

10 Case. 3
(9.7 pphm)

Case 2
(S. 6 pphn)

Case 1 (7. 2 pphm)

0
.174 6
04
@q I
N)4

U r-
4

0
0700 0800 0900 1000 lioO 1200 1300 1400
LOCAL TINM
Figure 6 Ozone Concentration.vs, Time for Trajectory of 7/9/75.
Arriving at Camarillo us..ng Case 1, 2, and 3 initial
conditions-(Ventura Moderate 0 3 rase)

A 7@'

14
B

PO 14
Ul

C
12

Figure 7 Trajectories used in In itial Con .di ti Ion simulation
A: S/l/75 B: 7/18/74 C: T/2S/7S D: 7/9/75

TABLE 26:
RESULTS OF THE SIMULATIONS TO ASSESS OZONE IMPACTS''
CASE 1, 2, AND 3 OIL DEVELOPMENT

OIL
DATE OF ORIGINAL FUTURE DEVELOPMENT 03 CONCENTRATION.,
TRAJECTORY STATION YEAR SCENARIO AT ARRIVAL (pphm)

A 5/l/7.5 Cathedral Oaks 1985 Case 1 5.0
Case 2 8.8
Case 3 10.5
B 7/18/74 State Street 1985 Case 1 9.8
Case 2 17.7
Case 3 22.1
C 9/25/75 Ventura 1985 Case 1 14.9
Case 2 16.9
Case 3 17.8
D 7/9/75 Camarillo 1985 Case 1 7.2
Case 2 8.6
Case 3 9.7

I M P A C T S 0 F P 0 1 N T S 0 U R C E E M I S S 1 0 N S U P 0 N
0 X I D A N T C 0 N C E N T R A T 1 0 N S

The second method for assessing OCS oil facility impacts-entails the
inclusion of point source emission fluxes from indivi-dual facilities in the
ARTSIM input module, and comparing oxidant concentrations at onshore monitoring
stations for various emissions combinations. In each case, the baseline run in-
cludes vehicles and other non-petroleum7site emissions but neglects,all petroleum
production and handling facilities. Representative emissions from the latter
were then included in 'subsequent simulation runs, with all other variables (includ-
ing initial concentrations) being held constant.

OFFSHORE PRODUCTION PLATFORMS

Estimates of emissions from offshore production platforms were..obtained from.
the work of Leach and have been listed in this chapter. 65/ Trajectories
were selected to encompass both average and high oxidant@-days for each county-.

The trajectory of May 1, 1975, selected earlier for modeling initial concen-
tration impactsS was used again here since-it represented a moderate ozone day
for Santa Barbara and also traversed the Santa Ynez tract and Exxon's Hondo dis-
covery. Case 2 initial conditions (see OXIDANT VARIATION-DUE TO CHANGES IN AMBIENT
PRECURSOR CONCENTRATIONS above)-were used for both runs. AnFi-c-ipated emissions for
the Hondo platform, assuming production of 80,000 B/D in 1985, were inserted in
the second run. The results, depicted graphically in Figure 8,.illustrate the
initial ozone-scavenging effects of NO emissions. After several hours, however,
ozone concentration overtook and surpassed that of the baseline case, reaching a
level -of 10.2 pphm at the time of arrival at Cathedral Oaks (versus 8.8 pphm for
the baseline case).

. Subsequent platform-impact runs were conducted for-four additional trajec-
tories incorporating emissions from three separate potential platforms. Ozone

252

10 - (10. 2 pphm)

(8.8 pphm)

8
0

41
r- -% Baseline Run
0 rZ
U 4
N) = P4
L" 0 cl, 6
WU

Hondo Emissions-Added

0
0700 0800 0900 1000 1100 1-200 1300
LOCAL TIME
Figure 8 Ozone Concentration vs. 7"ime for Trajectory of" 5/l/7-S
Arriving at Cathcdral Oalks, Modelinp, eff-c-.ts (-@-F 14nrr4in

concentration at time of arrival at the respective monitoring station is listed
in Table 27 for both baseline and platform impact runs for each of the modeling
days. As is evident, ozone increases from platform emissions are greatest-on
the moderate ozone days, both in magnitude and percentage, compared to baseline
values. Figure 9 shows plots of the trajectories described here.

TABLE 27:
OZONE IMPACTS OF OFFSHORE PLATFORMS FOR SELECTED MODELING DAYS

DATE OF PLATFORM PEAK 03 CONCENTRATION (pphm)
ORIGINAL (TRACT) FUTURE NO WITH %
TRAJECTORY STATION MODELED YEAR PLATFORM PLATFORM INCREASE

A 5/l/75 Cathedral Oaks Hondo 1985 8.8 10.2 15.9
(Santa Ynez)
B 7/18/74 Fairview (Oak Ridge) 1985 18.6 19.0 2.2'
C 7/10/75 Ojai (Pitas Pt.) 1985 18.9 19.5 3.2
D 9/25/75 Camarillo (Oak Ridge) 1983 16.1 16.8 4.2
E 7/9/75 Camarillo (Santa Clara) 1983 8.8 9.7 10.2

TREATMENT AND SEPARATION FACILITIES

According to Lind, 14 onshore treatment and separation (T & S) facilittes
were in operation in 1976 to handle Santa Barbara Channel oil and/or gas. 66/ By far
the largest throughput occurred at Mobil's.Rincon facility, an estimated @24_,500
barrels oil and 11,300,000 cubic feet gas per day. Emission factors for 'T & S
operations are discussed earlier, and estimated emissions for existing study area
facilities are listed in Table 11.

Lind's prognoses for future Channeldevelopment indicate that, if petro-
leum production increases significantly, the majority of existing facilities would
experience increased throughput and new plants could be built. 67/ The extent and
location of increased throughput would, of course, depend upon the characteristics
of offshore production.

Still unresolved at present is the fate of Exxon's handling facility to support
offshore operations at the Hondo site. Originally proposed was an onshore T & S
plant at Las Flores Canyon which could process both oil and gas and handle through-
put from the entire Santa Ynez unit, for which production estimates are as high as
300,000 B/D. Owing to conditions imposed by the State of California Coastal Commis-
sion concerning transport of the processed crude through a pipeline, Exxon has
announced plans to construct an offshore processing plant in federal waters near
Hondo, and has received permission from the Interior Department to do so. Expected
throughput at the offshore facility would not exceed 60,000 B/D, according to Exxon,
and gas processing would not be possible. Emissions from the proposed offshore site
were included as one of the modeling scenarios in this section.

Methodology for the T & S impact simulations was identical to that used in the
platform runs described in the preceding section. Future baseline runs assumed
Case 2 (moderate development) initial conditions, and no oil production-related

254

13
9
A ;2

C
B6441,rooooe.
13
Ln
D

E 12

rz=

Figure 9 Trajectories Utilized in Platform impact simulation
.A: 5/1/75 B: 7/18/74 C: 7/10/75 D: 9/251/75
E: 7/9/75

emissions. In subsequent runs emission fluxes expected within lease units traversed
by the trajectory were inserted and ozone production for the simulations compared.

The trajectory of May 1, 1975, was again selected to model emissions impact of
Santa Ynez unit facilities. In addition to the baseline case, two emissions
scenarios were modeled: the first assumed that OS&T storage tanks and production
loading were controlled, the second that vapor recovery took place. Production of
60,000 B/D was assumed (future year 1985). Emissions would result from loading
(the processing plant would be a converted tanker), storage, and process.ing. Figure
10 shows ozone-time.history for the three simulation runs.

Additional impact simulations for T & S faciliti.es were conducted for the
following sites and receptor locations: Mobil/Rincon -- Ojai; Ventura coastline
(possible future site) -- Simi; Mandalay Beach (possible future site) -- Santa Paula.
Results of the runs, listing peak baseline/impact run ozone values, appear in Table
28. The magnitude of ozone increase from T & S emissions was largest for the Simi tra-
Jectory (presumably because of Simi's distance from the coast, allowing ample ozone
buildup time, and because the projected Ventura coastline plant would have higher
throughput than any of the other three listed in Table 28). Plots of the trajec-
tories appear in Figure 11.

Table 28:
OZONE IMPACTS OF TREATMENT AND SEPARATION FACILITIES FOR
SELECTED MODELING DAYS

DATE OF PEAK 03 CONCENTRATION (pphm)
ORIGINAL FACILITY FUTURE NO WITH %
TRAJECTORY STATION MODELED YEAR FACILITY FACILITY INCREASE

A 5/l/75 Cathedral Oaks Hondo 1985 8.8 10.4 18.2
Offshore
B 7/10/75 Ojai Mobil/Rincon 1985 18.0 19.9 10.6
C 9/25/75 Santa Paula Mandalay Beach 1983 12.8 14.3 11.7
D 7/10/75 Simi Ventura 1993 16.3 18.8 15.3
Coastline

MARINE TERMINALS

Pollutant emissions resulting from marine terminal activities can be divided
into two groups: exhaust emissions.generated by ship engines and released through
stacks, and ullage vapors displaced from cargo tanks during loading, unloading, or
purging operations. Emissions factors for these processes were discussed in earlier
sections of this chapter.

The procedure for assessing ozone impact of marine terminal emissions was
identical to that used for platform and T & S impacts discussed previously. Base-
line runs were selected for both prevailing and high 03 days, and for existing as
well as proposed terminals. Impact runs assumed that tanker loading was in progress
at the time the air parcel traversed the site. Peak 03 values were then compared
for the tanker and no-tanker cases.

256

OS&T without Vapor
Recovery (10.4 pphm)
10.

(9.4 pphm)

(8.8 pphm)

Baseline Case

P. OS&T with Vapor
Recovery
0
6
N3 Cd
$-,
+j

0
U

0
1100
0700 0800 0960 1000 1200
LOCAL TIME
Fi re 10 Ozone Concen ration vs. Time forTrajectory of 5/1/75
gu t I &- -,,;it".
Arriving at Cathedral Oaks. Ef@ect-S- of "Me-0 OS

'13

B
12

10
C

Figure 11 Trajectories utilized in T S facility simulation
A: 5/1/75 B:,7,110/7S Ojai C: 9/251/75 D: 07/10/75 Simi

Computer simulations indicate that marine terminal impacts would be far
greater than those of the other facilities studied. As an example, the
results for the trajectory of July 18, 1974, which passed over AMINOIL's Ellwood
terminal prior to arriving at the Fairview APCD station, are shown in Figure 12..
Combustion and ullage emissions, according to the simulation, increased peak 1@ity
from 18.6 to 20.1 pphm (an 8% increase) despite the fact that the AMINOIL faci
is one of the smallest study area terminals.

The potential impact of a larger facility was modeled by considering the
trajectory of July 19, 1975, which arrived at Simi at 1300 after,passing over a
site which Lind indicates might be the location of a future Ventura County
marine terminal. 68/ Lind projects that the terminal would have a pumping rate of
20,000 barrels peF-hour and therefore would emit over 470-lb/hr RHC from ullage
losses alone (see Table 9 of this chapter). The baseline run for this example
reached a peak 0 concentration of 16.3 pphm. When marine terminal emissions were
added, however, 83 jumped to 20.4 pphm at 1300, an increase of 25%.
In the case of Exxon's Hondo production, several handling and transportation
scenarios have been discussed, In an attempt to model all possible contingencies,
four alternative plans were considered. The first assumes that emissions from
only the platform are generated offshore -- this is the "pipeline alternative"
case, and assumes that no marine vessels are involved in oil transport on the given
day. The second case assumes that Exxon's offshore processing facility is built,
and includes emissions from the platform, the converted tanker, and a 6,000 barrel
per hour marine terminal. For the third and fourth cases, an onshore processing
facility with offshore marine terminal was assumed. Emission fluxes were based on
Lind's low and high pumping rate estimates for the terminal of 13,000 and
25,000 barrels per hour, respectively. 69/

Ozone impacts for the various alternatives, using the trajectory and conditions
of May 1, 1975, are displayed in Figure 13. 03 concentration at the time of arrival
at the Fairview station was lowest for the baseline case (8.8 pphm) and grew increas-
-ingly for the platform-only (10.2 pphm), platform plus offshore complex (15.9 pphm),
platform plus 13,000 barrels per hour terminal (23.4 pphm), and platform plus 25,000
barrels per hour terminal (36.4 pphm) cases. Figure 14 shows plots of the four
trajectories used in the simulation.

Results of the marine terminal simulations are listed in Table 29.

- 259
18-76658

Tanker loading emissions at
AMINOIL Ellwood added
(20.1 pphm)
.20 (18.6 pphm)

Baseline Run

15.

10-

04- 1000 li0o 126o 1300 1400
0700 0800 0900 ons Impact.
Figure 12 Ozone Concentration vs. Time-Point Source Emissi
Trajectory of 7/18/74, arriving at Fairview Station.

Legend:
(22.9 pphm)
I Baseline Run: no Hondo emissions
2 Hondo platform emissions added
20 3 Platform + OT&S + 6,000 bbl/hr MT
4 Platform + OT&S + 13,000 bbl/hr MT
5 Platform + OT&S + 25,000 bbl/hr MIT (17.0 pphm)

ON
(1,3.0 pphn)

10 1 0. 2pphm)
2 (8.8 -pphm)
1

0 T
0700 0800 0900 1000 1100 1200 1300

Figure 13 Ozone Concentration vs. Time- Point Sou'rce tIM.Issions Inpact.
Trajecto-ry of 7/18/74 arriving at Fairview Station.

10
A 8.--. 10. Ile 1 12
9 13
7/ 12.

B 1PO

Figure 14 Trajectories Utilized in Marine Terminal simulations
A: S/l/75 B: 7/18/74 C: 9/25/75 D: 7/10/75

TABLE 29:
OZONE IMPACTS OF MARINE TERMINAL EMISSIONS FOR SELECTED MODELING DAYS

DATE OF PEAK 03 CONCENTRATION (pphm)
ORIGINAL FACILITY FUTURE NO WITH %
TRAJECTORY STATION MODELED YEAR FACILITY FACILITY INCREASE

A 5/l/75 Cathedral Oaks Platform Only 1985 8.8 10.2 15.9
Platform + 1985 8.8 13.0 47.7
OT&S -@
6,000 barrels
per hour MT
Platform + 1985 8.8 17.0 93.2
OT&S +
13,000 barrels
per hour MT
Platform + 1985 8.8 22.9 160.2
OT&S +
25,OOU barrels -
per hour MT
B 7/18/74 Fairview AMINOIL 1985 18.6 20.1 8.1
Ellwood
C 7/10/75 Santa Paula Union or Getty 1983 18.4 20.0 8.7
(Ventura)
D 7/10/75 Simi Ventura County 1993 16.3 20.4 25.2
(proposed)

Tanker fugitive emissions have been a source of controversy for many years
(see ENVIRONMENTAL SETTING). Emission fluxes have been shown to be
functions of a number of factors: tanker size, area-to-volume ratio, composition
of previous cargo, ullage, vapor pressure, and tank condition are notable
examples. It may be fallacious, therefore, to select a single emission factor'
to account for all combinations of the above variables. For that reason, it was
decided to conduct a sensitivity analysis for marine terminal oxidant impact in
which a variety.of emission factors for fugitive HC was utilized.

The simulation run selected was the July 10,-1975i Simi-arrival trajectory
which passed over a hypothetical Ventura County terminal (future year 1993). Three
emission fqctors were selected (in addition to the 1.9 lb/101 911 used previously):
4.0 lbs/101 gal loaded, representing an upper bound; 1.3.lbs/10 gal, from MacKenzie
and Rau 70/ for 250,000 DWT ships; and, 0.8 lbs/103 gal, selected as a lower bound
for load'T-ng emissions. Table 30 lists results of the simulation. In all cases,
ozone increase over the baseline peak value (1-6.3 pphm) was significant. Peak ozone
for the impact runs varied from 18.2 pphm (with the lowest emission factor) to 25.0
pphm (with the highest). Even using the lower figure, projected ozone increase
from the 20,000 barrels per hour loading facility would be approximately 12%.

263

TABLE 30:
OZONE IMPACT OF HYPOTHETICAL VENTURA COUNTY MARINE TERMINAL FOR VARIOUS LOADING
EMISSION RATES; TRAJECTORY OF 7/10/75, SIMI, USING 1993 CONDITIONS
EMISS@ON RATE PEAK 03 CONCENTRATION (pphm)
Obs HC/10 gal LOADED) NO FACILITY WITH FACILITY INCREASE
0.8 16/3 18.2 11.6
1.3 16.3 19.2 17.5
1.9 16.3 20.4 25.2
4.0 16.3 25.0 53.2

IMPACT OF HYDROCARBON EMISSIONS FROM SEEPS

Seepage of crude oil from the ocean bottom has occurred for many years along
the coast of California. In particular, certain offshore areas west of Santa
Barbara have been known to emit particularly large quantities of oil. What is
perhaps the largest seep lies seaward of Coal Oil Point and was the scene of a
study conducted by Meteorology Research, Inc., to determine vapor emissions of
hydrocarbon compounds from the resultant slick. Published in 1976, the study
yielded an estimated emission rate of 63 gm/sec, or about six tons/day. 71./

Using the trajectory of July 18, 1974, which traversed the normal path of the
slick, the oxidant effect of the HC vapors was assessed. A reactiv-ity of 30% and
plume width of 100 meters were assumed in determining RHC content and plume en-
trainment time, respectively. The results, as shown in Figure 15, indicate an
increase in 03 at the Fairview station from 18.6 pphm (baseline case) to 19.0 pphm,
with seep emissions included. This increase is approximately one-fourth as large
as the similar increase indicated for the nearby AMINOIL terminal (see previous
section).

IMPACT OF HYDROCARBON EMISSIONS FROM OIL SPILLS

In the past, occasional spills of crude oil and processed liquids have occurred
on offshore and inland waters. The most immediate example of such a spill in the
study area was the 1969 blowout of a well at Union's Platform A, located on the Dos
Cuadras tract in OCS waters.. Estimates of the total volume of oil released range
from 18,000 to several hundred thousand barrels. 72/ In addition to platform ac-
cidents, spill categories include terminal operat@ions, pipeline failures, and ship
incidents.

Few published analyses of hydrocarbon vapors released from oil slicks on water
are in existence. Those which are available tend to be rather limited in scope.
Nevertheless, by assembling excerpts from several different publications, it was
possible to formulate a model relating spill volume to slick size, film thickness,
and percent evaporation (by carbon number) as functions of time after the
spill. The formulation, which is rather lengthy, is described in detail in
Appendix Ii.
Assuming an original spill volume of POO tons (about 6,600 barrels), we
obtained an estimated slick area of 1.3 km 2after one day, and 5.9 tons/hr RHC
emitted from the surface, or 4.5 tons/hr-km . Thus, assuming a hypothetical day-
old slick in calm seas off the Ventura County coast, the trajectory of July 10,

264

Seep Emissions Added
20
(19.0 pphm)
Baseli @eRun (18.6 pphm)
16

12 -

8.,

-T-
1000 1100 1200 1300 1400
0700 0800 0900
Figure 15 Ozone Concentration vs. Time-Point Source Emission Impact.
Trajectory of 7/18/74, arriving at Fairview Station.

1975, arriving at Simi, was chosen for the analysis, using predicted initial
conditionsand surface emissions for 1983. The result was an increase in ozone
at the receptor from 17.0 pphm (baseline run) to 28.1 pphm (,spill emissions added).
Ozone-time histories appear in Figure 16. It is felt that this run represents
worst-case conditions since calm seas and a higher ozone potential day were assumed.

It should be pointed out that the ARTSIM version used in the modeling (ten
species including only one hydrocarbon) does not distinguish among individual
hydrocarbon classes such as olefins and alkanes; the former is much more reactive
and is an important component of motor vehicle exhaust, while spill emissions are
composed primarily of the latter. In order to compensate for this discrepancy,
spill-emitted HC was given a reactivity value of 30% despite the fact that some
reactivity-classification systems assign a value greater than 80%.

The ARTSIM spill-emissions runs have indicated that oil spills can be a
significant source of reactive hydrocarbon species which can lead to high ozone
increases under certain conditions. It is hoped that, in the future, more sophis-
ticated modeling techniques, including improved emissions information and several
hydrocarbon species, will enable a better understanding of a potentially crucial
air quality problem.

RADIUS OF INFLUENCE OF LARGE POINT SOURCES

The results of the tanker impact simulations described above indicated that
fugitive hydrocarbons released during loading could lead to greatly enhanced in-
plume ozone concentrations in the study area. It was suspected that additive
effects of two intersecting or concurrent plumes might yield further ozone increases.
In order to assess such a dual-plume effect, an attempt was made to determine the
effective radius of influence of a tanker-loading plume and thus suggest appropriate
spacing between successive terminals undergoing simultaneous loading.

Analysis of the many trajectories calculated for worst-case ozone days indi-
cated a predominance of relatively low-wind speeds along the Santa Barbara County
south coast. Velocities frequently fell in the five to seven mph range. Assuming
an ozone buildup time of four hours, total transport of 20 to 28 miles might be
expected. In order to verify this result, which was obtained in a somewhat sub-
jective manner, ihe following procedure was employed:

1. Assume:
- wind speed of 5 mph
- F (stable) stability
- 25 mile downwind distance
- source strength 127 gm/sec (corresponding to 13,000 barrels per hour
tanker loading rate with resultant fugitive HC emissions)
- c- , a- according to Turner 73/
Y Z -
2. Using the Gaussian plume formula for centerline concentrations downwind
of a continuous point source,

7 Q

2 C

266

30.
M.1 pphm)

Spill Emissions Added

(17.0 pph-i)

Baseline Run

-10,

0-
0700 0800 0900 1000 1100 1200 1300
1 .
.Figure 16, Ozone Concentration vs. Time.Point@Source Emissions Impact.
Trajectory of 7/18/74, arriving at Fairview Station.

where concentration (g/m3

Q = source strength (g/sec)

t1i = wind speed (m/sec)

= horizontal-and vertical diffusion coefficients,
respectively
The concentrations of RHC at 25 miles is 134.2 ug/m3, which represents
84% of the federal three-hour standard.

3. Using the over-water 0- and 0-- of Harrison and Maas,'74/, RHC concentra-
z
tions of nearly 5000 u@/O are obtained. These diffu'sion coeffi.cients
were determined during a monitoring studv near the Coal Oil Point seep
off Goleta, but were measured during the month of Ja.nuary and hence may
not be directly applicable to summer smog-season conditions.

AIR QUALITY IMPACTS OF OTHER POLLUTANTS
N I T R 0 G E N D 1 0 X I D E ( N 0
NO has traditionally been of less concern than oxidants within the study area
because of the fact that the federal (5 pphm annual average) and California (25 pphm
hourly average) ambient air quality standards are rarely exceeded. NO 2 is known
as a secondary pollutant, since it occurs chiefly as a result of atmospheric chemi-
cal processes involving primary pollutants, those emitted directly into-the atmos-
phere, particularly nitric oxide (NO). Concentrations of N02 to be used in air
quality modeling were obtained from the output of the ARTSIM model,.in which N02 is
one of the reactive species.

Onshore N02 impacts of petroleum production and related operations were
assessed in the same way as oxidant impacts discussed in the previous chapter:
from ambient backg-round levels (initial condition simulation) an-d as a
direct result of point source emissions. In using the first technique, it was
assumed that the initial N02:NO ratio remained constant* for any level of NOX
emissions. The latter used the assumption that all NOX was emitted as NO.
Results of the initial condition simulation for N02 are shown in Table 31.
In all cases, the difference between N02 concentrations for Cases 1, 2, and 3
development was negligible; the largest spread was only 0.5 pphm.

Point source emissions impacts were, in some cases, more significant. Plat-
form impacts, for example, as shown in Table 32, range from a 0.4 pphm increase
(9/25/75 Camarillo) to a 1.8 pphm increase (5/l/75 Cathedral Oaks), generally
larger than initial concentration effects but still rather small changes. T & S

*NO2 :NO 2.1 75/

268

facilities, however, would produce much higher N02 impacts, as shown in Table 33.
Among the cases studied, the Exxon offshore facility would create the greatest
impact, an increase of over 8 pphm from 1.8 to 9.9; nevertheless, all the values
shown fall well within the California one-hour standard of 25 pphm. Finally, N02
air quality calculations for marine terminal emissions (including tanker emissions
both in-,berth and underway) resulted in negligible increases over baseline values.

TABLE 31:
IMPACTS ON N02 CONCENTRATIONS FOR INITIAL CONDITION SIMULATIONS (ONE-HOUR AVERAGES)
DATE OF ORIGINAL FUTURE N02 CONCENTRATION (pphm)
TRAJECTORY STATION YEAR CASE I CASE 2 CIASE 3

5/l/75 Cathedral Oaks 1985 1.8 2.2 2.3
7/18/74 Fairview 1985 1.7 1.8 1.8
9/25/75 Ventura 1985 3.2 3.3 3.3
7/9/75 Camarillo 1983 1.8 1.9 2.0

TABLE 32:
IMPACTS OF OFFSHORE PLATFORMS UPON N02 CONCENTRATIONS FOR SELECTED DAYS
(ONE.-HOUR AVERAGES)

DATE OF ORIGINAL FACILITY N02 CONCENTRATION (pphm)
TRAJECTORY STATION MODELED NO PLATFORM WITH PLATFORM

5/l/75 Cathedral Oaks Hondo 1.8 3.6
7/18/74 Fairview Oak Ridge 1.6 2.3
9/25/75 Camarillo Oak Ridge 3.6 4.0
7/10/75 Ojai Pitas Point 2.4 3.1
7/9/75 Camarillo Santa Clara 1.8 2.5

TABLE 33:
IMPACTS OF T & S FACILITIES UPON N02 CONCENTRATIONS FOR SELECTED DAYS
(ONE-HOUR AVERAGES)
DATE OF ORIGINAL FACILITY N02 CONCENTRATION (pphm)
TRAJECTORY STATION MODELED NO FACILITY WITH FACILITY

5/l/75 Cathedral Oaks Hondo 1.8 9.9
Offshore
7/10/75 Ojai Mobil/ 2.4 5.0
Rincon
7/10/75 Simi Ventura 3.0 6.1
Coastline
(possible
future)
9/25/75 Santa Paula Mandalay 2.9 4.9
(possible
future)

269

CARBON MONOXI DE (CO

As reported earlier in the ARTSIM BASELINE RUNS section, petroleum facility
CO effluent would represent a very small percentage of total study emissions.
Results of the ARTSIM simulation, as might be expected, showed almost no differ-
ence in CO levels as a result of petroleum activities for either the initial
condition simulations or point source impact runs.

S U L F U R 0 X I D ES ( S 0
Sulfur oxides, in particular sulfur dioxide (S02), are emitted as a product
of combustion of fuels containing sulfur compounds. According to Leach
sulfur oxides emitted during oil production and transport would result from diesel
engine exhaust and gas flaring. Using a production level of 200,000 B/D, Leach
estimated Channel S02 emissions at 1.39 tons per day. 76/ This figure represents less
than 2% of SOX emitted in the study area. Since long-term, annual, averages of SO
have never exceeded the three pphm federal annual standard, it is expected that ol-
industry-related S02 emissions would exert a negligible impact upon long-term
ambient concentrations in the study area. 77/

It is expected, therefore, that the most significant effect Of S02
emissions would be short-term local concentrations in the immediate vicinity of a
facility. The most stringent short-term standards are California's one-hour (50 pphm)
and 24-hour (four pphm) limits. In order to model the S02 impacts, ERT's Point Source
Diffusion Model (PSDM), a Gaussion-type model, was used. in regions of homogeneous
terrain (including over-water areas), the Gaussian assumption has been shown to give
reasonably good approximations of actual observed concentrations. 78/ For that
reason, PSDM was selected for modeling of primary pollutants S02 a-n-j H2S over flat
terrain (water and coastal plains).

Emission rates Of S02 for platforms, T & S facilities, and tankers are listed
in the EXISTING EMISSIONS section. All sources listed, with the exception of tank-
ers in transit, represent fixed, continuous point sources and were modeled using
PSDM. Tanker movement impacts were assessed by designing a hypothetical worst case
in which the ship is assumed to remain for an hour within a moving air parcel of
one sqyare kilometer and 50-meter depth. The S02 emissions of 14.2 lb/hr were assumed
to be evenly distributed throughout the parcel. The result is an hourly averaqe
concentration of 4.9 pphm, which represents less than 10% of the state one-houir
standard. Thus, even this highly unlikely and unfavorable meteorological occur-
rence would result in rather low S02 levels.
PSDM-derived S02 concentrations were determined for three source types:
platforms, T & S facilities, and tankers in berth. Peak one-hour average concen-
trations are listed in Table 34 for selected existing and possible future facilities
by Pasquill-Gifford stability, wind speed, and downwind receptor distance. In only
one case does predicted one-hour S02 approach the California standard of 50@pphm:
the Ventura coastline T & S facility mentioned by Lind as a possible alternative
for future development, 79/ with maximum expected throughput of 150,000 B/D oil
and 150 million SCF/D ga7s-.* According to the PSMS calculations, such a facility,

*This facility is purely hypothetical. It assumes oil and gas that would be pro-
duced in the Outer Banks would be processed onshore. To date, there have been no
discoveries made in these areas. Even if commercial discoveries are made, the pro-
cessing of crude oil and natural gas might occur on fixed structures at the produc-
ing site rather than at a consolidated onshore plant.
270

which 'would emit an estimated 74.2 lb/hr of S02, would yield worst-case one-hour
S02 concentrations,of 44.5 pphm, which represents 89% of the state standard.
According to the five-year stability-wind rose for nearby Point Mugu, this
condition would occur about 1.4% of the time (total for all wind direction, D
stability, and appropriate wind speed class). 80/ Although the maximum concentrations
fall below the standard, it is felt that the ef-fect may'be a critical one in view
of other SO emissions which might occur in the vicinity of such a facility (e.g.,
tanker traffic emissions, increased vehicle emissions).

TABLE 34:
MAXIMUM ONE-HOUR CONCENTRATIONS OF S02 FOR VARIOUS OIL AND GAS FACILITIES
(ASSUMED MIXING DEPTH 100 METERS)

so? S02 DOWNWIND
PRODUCTION EMISSIONS CONCENTRATION DISTANCE WIND SPEED
FACILITY THROUGHPUT (lb/hr) (pphm) (m.) STABILITY (m/sec)

PLATFORM 13,550 B/D* 4.5 1.3 1000 D (Neutral) 5.4
A
PLATFORM 60,000 B/D** 19.9 5.9 1000 D 5.4
HONDO
T & S 2,600 B/D* 6.8 4.0 100 D 12.1
(Chansl.or)
T & S 150,000 B/D** 74.2 44.2 100 D 12.1
(V2ntura
Coast)
TANKER 175,000 B/D 1.7 1.4 700 E (Stable) 3.6

*1976 figures
**possible future throughputs

H Y D R 0 G E N S U L F I D E H S

Emissions of H2S result almost entirely from venting and processing losses
in the handling and treatment of natural gas. 81 / According to Leach, such
losses amount to 2.6 lbs H2S per 106 SCF gas procassed (assuming 0.9% H2@ content
by volume of raw gas, and total losses of 210 lbs per 106 SCF processed), and
would occur exclusively during processing operations. H2S-imp-acts were assessed
using PSDM, with throughputs (and thus emissions) obtained from Lind. 82/ Results
of the s1mulations, showing maximum H2S one-hour concentrations predicTed for
several existing and possible future processing sites, appear in Table 35. Although
maximum concentrations expected for currently operating facilities are less than
the California one-hour standard of three pphm, PSDM calculations indicate viola-
tions for each of Lind's three-largest futuee throughput totals:- at Mobil/Rincon
-(assuming processing at that location of all GTUM and Sun tract gas); ai Exxon/
Las Floras (onshore pr ?cessing of all Santa Ynez unit gas, assuming peak future
throughput of 100 x 10 SCF/D); and at the Ventura coastline alternative (assuming
throughput of 150 x 106 SCF/D). These findings indicate potential future problems
at large gas processing facilities, and point out the necessity for careful analysis

271

of H2S emissions impacts at T & S sites. The conditions described in Table 35
are rather common. 83/ Slightly unstable conditions and appropriate wind speed
class (0-1.3) occurred at Point Mugu 1.4% of the time over a five-year period
(total for all wind directions), or an average of 123 hours per year. National
standards are violated if NAAQS concentrations are exceeded more than once
per year.

TABLE 35:
MAX IMUM EXPECTED ONE-HOUR H S CONCENTRATIONS RESULTING FROM NATURAL GAS
PROCESSING EMISSIONS (ASSUMiD MIXING DEPTH 100 METERS)

THROQGHPUT H2S H S DOWNWIND
(101, SCF EMISSIONS CONCEURATION DISTANCE WIND SPEED
FACILITY GAS/DAY) (lb/hr) (pphm) (m.) STABILITY (m/sec)
CHANSLOR 13.7* 1.48 1.3 100 c (slightly 0.9
MOBIL/ 11.3* 1.22 1.1 100 unstable) 0.9
RINCON C
MOBIL/ 86.1* 9.33 8.3 100 C 0.9
RINCON
EXXON/ 100.0** 10.83 9.7 100 C 0.9
LAS FLORES
VENTURA 150.0** 16.25 14.5 100 C 0.9
COASTLINE

*1976 figures
"possible future throughputs

CONCLUSIONS .

SUMMARY OF FINDINGS

The most immediate conclusion drawn from the OCS Development Inpact Study is
that certain aspects of oil and gas production and handling can significantly af-
fect local and regional air quality. Impacts of oil industry processes on concen-
trations of both primary (S02, H2S, CO) and secondary (03, @02) pollutants were
assessed using three methods: a Gaussian-type model for primary pollutants; ARTSIM
photochemical/diffusion model to assess effects of changes in ambient precursor
levels; and, ARTSIM again to model impacts of individual point or area sources. Of
chief concern in this study were concentrations Of 03, S029 and H2S.; but all pol-
lutants listed above were discussed.

Among routine process emissions expected to occur in and near the Channel,
fugitive hydrocarbons released during tanker loading would, according to the simu-
lations, have the greatest impact upon 03 and N02 concentrations. In order to
account for variations in loading procedures, ship size, and other conditions, a
sensitivity analysis was carried out using several emission rates, because the choice of
a single value to apply to all loadings might not be valid. Results of the sensitivity

272

analysis indicated that.ozone increases (above baseline values) are directly pro-
portional to loading emissions. Doubling the emission rate, for example, would
very nearly double the ozone increase. An additional observation is that relative
ozone increase (percentage above baseline values) caused by marine terminal emis-
sions was greatest for the moderate ozone day modeled; that is probably due to the
fact that background concentrations of NO (which acts locally as an ozone scavenger
and thus can create short-term ozone decreases) were lower on moderate 03 days than
on "worst case" days.

It is evident from the-simulations that loading rate is a cruci.al emission para-
meter since the mass of HC liberated is proportional to volume loaded. Thus higher
loading rates imply higher emission rates. For that reason, slower loading appears
to be-a potential mitigating measure. Other methods for reducing tanker impacts
include partial loadi.ng and.temporal-geographic restrictions. Much of the hydro-
carbon-rich-vapor which is liberated during.loading lies very near the liquid
@surface and thus is released only as the crude reaches the top of the tank. Ap-
proximately 83% of generatedT.component vapor emissions (those resulting from the
liquid being loaded.rather than previ:ous-load residue) occur during the final 15
feet of filling. 84/ Since generated-component HC represented 37% of total tanker
loading emissions, the latter would be reduced by 31% if final true ullage -
(distance between,the liquid surface and roof of.the tank) of 15 feet was maintained.
This measure alone would reduce the tanker-loading emission factor from 1.9 to 1.3
lbs/103 gal, and would represent a reduction of over 2,400 lbs hydrocarbons for
every 100,000 barrels loaded.

Additional minimization of tanker impacts might be possible if timing and
si.ting considerations were followed. For exampl-e, it is clear that multiple
.tanker-loadings on one day could yield significantly higher study area ozone con-
.centrations than in a case of one tanker per day. The e 'ffect would be magnified
if the, marine termina-ls were,relatively close together. ERT's analysis indicates
that the east-west orientation of the south coast of Santa Barbara County, which
nearly parallels the prevailing wind direction, increases the chances of a single
air parcel pas-sing.over more than one marine terminal. The May 1, 1975, trajectory,
for example, passed dire,ctly over Exxon's proposed offshore terminal and later
came within one kilometer of Aminoil's Coal Oil Point.facility. If simultaneous
.loadings were to occur in such a situation, the additive effects of the super-
imposed plumes upon local ozone.concentrations could be significant. Preliminary
findings-indicate that -the radius of influence of marine terminal emi.ssion along
the above stretch of coastline is of the order of 25 miles during certain atmos-
pheric.conditions. Scheduling of tanker loading to prevent more.than one simul-
taneousevent within such a radius may be a key milti.gating measure for tanker
influences in the study-area. Due to differences in terrain and atmospheric con-
ditions,.'the aforementioned.radius of influence will vary for different locations.
Additi.o-n.a-l research is.needed.before a universally.applicable relationship-between
location, atmospheric conditions, and radius of influence can be obtained.

'Thus, although the -impact results reported in this chapter.indicate that
tanker loading would exert a significant effect on local ozone concentrations,
it is felt that such influences.could be minimized by adopting the three afore-
.mentioned mitigating measures: 1oad the tankers sl-owly@; maintain an ullage of
15.feet; and, adopt a..radius of influence standard which wouldli .mit tanker load-
ings to one-per day within any such distance.

.During the point source impact simulations described in this chapter,,effects
of-emissions from individual s-ites were analyzed. In.someJnstances,..however,

273

wind direction may be such that a facility lies within the plume of an upwind
source, causing a localized additive effect. Such an effect would be most common
and dramatic when sources are close together and aligned along prevailing wind
streamlines; for example, the three Dos Cuadras rigs are oriented east-west in
an area which sees frequent westerly winds. The ozone impact would be most
significant if transport between two marine terminals were to occur.

It appeared that the Hondo and Aminoil (Coal Oil Point) terminals might at
times lie on the same streamline. Similar occurrences for other terminal combi-
nations might occur as well.

Analysis of short-term S02 and H2S concentrations outlined in the 'AIR QUALITY
IMPACTS OF OTHER POLLUTANTS section has indicated that California one-hour air
quality standards would be approached or exceeded near large T & S facilities.
The highest one-hour S02 concentration predicted by ERT's PSDM model was 44.2 pphm,
which represents 88% of the state standard. Ifother sources contributed ambient
levels of only six pphm, violation would occur. The state H2S standard, in fact,
would be exceeded because of T & S emissions alone: according to the modeling
results, any gas processing throughput greater than 32MM CF/D would result in
local exceedances of the three pphm one-hour standard. In both cases, the favored
mitigating measures involve limitation of facility size (since emissions are ex-
pressed as functions of throughput) and removal of sulfur compounds before effluent
is released into the atmosphere.

The OCS impact study was hampered by what proved to be a rather sparse data
base. In particular, valid wind and emissions information was not always avail-
able. It is hoped that, in the near future, valid and comprehensive field measure-
ment programs and the deployment of additional monitoring stations will enable air
quality researchers to conduct more definitive impact studies. ERT's suggestions
for future data base expansion are discussed in a subsequent section of this chapter.

E X X 0 N H 0 N D 0 / L A S F L 0 R E S S C E N A R 1 0 S

Because of current interest, Exxon"s Santa Ynez tract production and related
treatment and transport activities were studied in more detail than were any of
the other individual facility sites. Although Platform Hondo is currently nearing
completion, the ultimate configurations of the other facilities have not been de-
cided. For that reason, a wide range of possible alternatives was modeled.

At present, Exxon is proceeding with plans to construct an offshore storage/
marine terminal facility instead of the originally proposed onshore plant at Las
Flores Canyon. According to our findings, the offshore alternative would have a
greater effect on same-day ozone concentrations in the Goleta-Santa Barbara area
than would the onshore site, assuming equal emissions at the two sites. The
proposed offshore facility location would lie upwind of urban areas more fre-
quently than would the Las Flores site. In addition, transport from the OT&S to
the urban.areas (winds slightly south of west) is much more common on moderate-
to-high ozone days than is transport from Las Flores (west-northwest winds).
Finally, the configuration of the offshore facility (a converted tanker in conjunc-
tion with storage barges) indicates that fugitive HC emissions from double-loading
(continuous transfer from platform to OT&S and intermittent loading onto seagoing
tanker) would be higher per unit of production than for the onshore facility.
However, throughput for the offshore site would be limited to about 60,000 B/D,
while estimates for onshore throughput range as high as 300,000 B/D. 85/ Thus,
although emission rates are higher, per unit throughput, for the offsFo,-re facility,

274

the potentially greater capacity of a Las Flores.site could lead to differences
in total emissions.

In order to assess ozone impacts of various consolidation scenarios, ARTSIM
runs were made for several hypothetical cases: a single 60,000 B/D T & S facility;
two 30,000 B/D facilities; and, three 20,000 B/D plants. In the second and third
-cases, the facilities were assumed to be five kilometers apart and,traversed by
the trajectory. The result indicated negligible ozone differences for the three
runs. Concentrations Of S02 and H2S, however, would be affected significantly
by siting/throughput considerations. According to the simulation results reported
in AIR QUALITY IMPACTS OF OTHER POLLUTANTS, worst-case S02 concentrations,
directly proportional to throughput, would be twice as high near a 60,000 B/D
facility as those near a 30,000 B/D plant. H2S, proportional to gas processing
throughput, exhibits similar behavior, with emissions at a 70MM CF/D facility
twice those at a 35MM CF/D site. From the standpoint of primary pollutant con-
centrations, then, several small facilities are more desirable than one large one.
Recommended throughput limitations.and possible mitigating measures were discussed.
above.

Tanker loading rates, already identified as a critical emissions parameter,
are highly dependent upon the size and throughput of the handling facilities. In
addition, loading time, storage capacity, and frequency of tanker visits are inter-
dependent variables which influence emissions. Consequently, the three loading
rates selected and modeled for the proposed Exxon marine terminal represent a
rather large matrix of the above variables. For example, consider the 6,000
barrel per hour rate estimated for Exxon's offshore alternative. If we assume
production of 60,000 B/D, ten-hour loading time, and 120,000 barrel per tanker
loading, 15 tanker visits per month are required.; 80,000 B/D production would re-
quire 20 visits per month if loading time and storage remained constant; finally,
80,000 B/D production, 240,000 barrel storage, and 20-hour loading time would re-
quire 15 loadings.per month. Thus, by varying one or more parameters and using
the three (6,000, 13,000, and 25,000 B[M) loading rates, virtually any likely
combination of loading time or stc)rage capacity can be modeled.

According to the impact results shown in Figure 27, the low, medium, and high
loading rates yield significantly different downwind ozone concentrations. It is
suggested, therefore, that loading rate specifications be carefully considered in
formulation of planning decisions for such a facility. This aspect and other
potential mitigating measures @were discussed at length in the preceding section.

S U G G E S T 1 0 N S F 0 R A D D I T 1 0 N A L R E S E A R C H

The major problem confronting air quality researchers in the Santa Barbara-
Ventura area is lack of a comprehensive, well documented data base. Among the
more notable deficiencies, meteorological data and offshore emissions information
stand out.

Wind and stability are the meteorological parameters deemed most important
in modeling pollutant behavior near the surface. Pollutant concentrations are a
function of both advective and diffusive processes in the atmosphere; the former
are determined from wind speed and direction information, while the latter are
functions of stability. Although Ventura County-has.a number of surface wind
stations, the south coast of Santa Barbara County has only one continuous wind
station with readily available data: the Santa Barbara airport. In addition,

19-76658 275

data from the Santa Barbara Channel, over which all of the trajectories used in
this study originated, is very sparse. Deployment of additional wind monitors
along the Santa Barbara coast and in the Channel would greatly enrich the existing
meteorological data base and increase the validity of future air quality research.
Suggested optimum locations for such monitors are:

1. the Point Conception area;
2. Santa Barbara (preferably near the Harbor);
3. @Carpi nteri a ;
4. the Santa Barbara Channel (the obvious choice would be on.a drilling
platform) ; and,
5. the Channel Islands.

A number of methods for determining stability have appeared in the literature.
.A simple, widely used method employs wind speed and solar radiation data.
Vertical temperature structure (lapse rate and wind shear), obtained from rawin-
sonde soundings, is frequently used (our formulation utilized both) in stability
classification systems.. However, sounding data is not always ava-il'able; only at
Point Mugu are regularly scheduled sounding measurements taken. Unfortunately,
the great expense involved in providing sounding data (either balloon- or aircraft-
measured)'is a,serious drawback. Since lapse rates seem to correlate well at
coastal stations, it may be desirable to add measurement sites further inland
rather than at other coastal locations. 86/ The characteristics of study area stability
parameters* have been largely unexplored-;further research would be quite useful in
air quality transport studies using tracer materials.

@Most of the assumptions used to determine emissions from-oil and gas produc-
tion and handling facilities have been a source of debate between the various
.agencies involved. In some cases, emission rate calculations are based on out-
dated or inadequate information or are not universally applicable. In particular,
.offshore emission data are extremely sparse; platform and tanker information is
,often woefully inadequate. Now in progress are*several measurement studies
designed to improve the available data base. Results of these studies
are anxiously.awaited by researchers. But with equipment and techniques changing
rapidly, it may be necessary to continue the measurement process at regular inter-
vals in the future.

Improved modeling techniques will allow more accurate and sophisticated
characterization of air pollution processes. Among the noteworthy fields current-
ly being explored by modelers are: use.of a larger number of chemical species and
reactions (an updated version of ARTSIM currently-being.tested.has about 30 species);
modification of.trajectory models tolassess more accurately the influences of large
point sources; and, development of efficient but accurate qrid models eMDloyina an
Eulerian (cells fixed-in space) approach to air quality model-ing. Although more
expensive than the simple, more commonly used-models, the above methods can be far
more reliable, especially where a complete, appropriate data base exists.

With the likelihood of further industrial activity in the study area, par-
ticularly in-oil- and gas-related processes, every effort should be made to pro-
vide planners with a data base.that is sufficiently comprehensive to ensure the
valid'ity of such studies. Only then can decision makers provide'the public with
the valid, well informed judgment required to successfully balance environmental
quality with the energy-and economic needs which concern Ps all.

*See glossary.
276

APPENDIX A

VERTICAL EDDY DI FFUS ITY MODEL USED IN
THE ARTS IM CALCULATIONS

Vertical eddy diffusity (Kz) profiles used in the ARTSIM simulation were
obtained from a model which can be used for unstable, neutral, and stable cases
with and without inversion layers present. The scherne is based on the neutral-
stability work of Blackadar, with non-neutral, consideration derived partially
from the work of Egan-Mahoney, Ragland-Peirce, and Fulle. 87/ Measured
profiles published by Pasquill Were used for the purpose o_f7checking the
accuracy of the resultant values. 88/

NEUTRAL CASE

The given parameters specified by t he user for the neutral case are:
ug geostrophic wind speed (m/sec)
roughness height (m)

As an initial step, determine u*, the frictional Velocity. Using the Ragland-
Peirce method,
Cg 0.16(logloRo-1.8) (1)
Where
u
R q
0 z f
0
f Coriolis parameter 10-It sec -1
Then U* = C u9 (2)

The parameters u (z) and K (z) represent the mean wind speed and eddy dif-
fusivity value, respe@tively, aq a height z above the surface, for the neutral
case. They are determined according to

U*
Un(z) = k ln z (3)

K n(z) = JZA- (z)/(l+kz/,1)' (4)

where

k = von Karman constant 0.4
= 2.7xlO-4 u 9/f

277

NONNEUTRAL CASES

Diffusivity calculations for nonneutral situations are centered around deter-
mination of an appropriate stability parameter. Some researchers have 'Used quali-
tative stability classifications based on surface wind speed and isolation and
represented by letter designations; however, a more useful parameter is one based
on a quantitative approach. A commonly used stability parameter in such calcula-
tions is the Monin-Obhukov length L,
_u*3jVc
L kgH (5)

where U* = friction velocity
= air density
cp = pressure constant for dry air
e = ambient potential temperature
k = von Karman constant
g = gravitational acceleration
H = heat flux

with a range
L 0 unstable

L neutral

L _7 0 stable

Because straightforward calculation of L is sometimes difficult (due chiefly to
the heat flux measurement), other methods have been devised for its quantifica-
tion, including formulae based on Richardson's number. If vertical temperature
and wind structure are known, L can be determined using a relationship developed
by Fulle, which involves a stability paremeter a,
a 1 + .0025 )u - 1/2 (6)
0+-r)2 z

where
(OC/100 M.) (7)
z
z = height above surface (m.)
.u = wind speed at height z (m/sec)

Fulle's stability parameter was then separated into stable and unstable regimes,
and L determined:

278

a > 9.02 (stable regime)
L 5 (8)
ln(a/9.02)

a < 9.02 (unstable regime)
L 1
ln9"'
a

The vertical wind profile for both stable and unstable cases can be estimated by
using the neutral wind profile u nW determined in (2) such that

112
UW = U n (z)(1+1/L) (9)

UNSTABLE CASE (L< 0): The formulation of Egan-Mahoney is modified by the
addition of the term (1+kz/..a-) 112 and becomes
Kkz) - kn (z)(l-l/L)(l-l6z/Q 112 (10
1 + k z/,-L) 1/2
where KnW = neutral eddy diffusivity from (3)
2.7xlO-4 ug/F

(1-1/L) represents frictional velocity change
(1-16z/L) 1/2 is the heat flux term

STABLE CASE (L'@'O): Egan-Mahoney's stable case equation is used here with
slight modification:
K(z) = K n(z)(l-4/L)(l+4.7z/L)_ 1/4 (11)
where (1-4/L) represents frictional velocity change
(1+4.7z/L)- 1/4 is the heat flux term

INVERSION CONDITIONS

If an air parcel is capped by a temperature inversion, the eddy diffusivity
within the lower layer can be estimated by modification of equations (3), (9),_
and (10). In all such cases, the resulting (Kz) obtained in the equations is
multiplied by the term introduced by Egan-Mahoney
(H-z/H) 1/3

where H height of the inversion base.

279

MODEL COMPARBON

Pasquill has presented a set of diffusivity profiles based on statisti-
cal theory and observations. In order to compare Pasquill's results with those
of the model, calculations of the latter were computed using similar geostrophic
wind, roughness height, and stability. As evidenced in Figure Al, which gives
profiles for unstable, neutral, and stable cases, respectively, the correlation
between the two schemes is reasonably good, although the height of maximum kz is
in all cases lower in the current model than in the Pasquill profiles.

280

Unstabi
Height
above
surface Neutral
(km) CL= cc

Stable

CL=5)

V-
lot 2 to too
Kz (m /sec)
Figure Al Vertical Eddy Diffusivities CKZ versus Height from Current Model
(solid lines) and Pasquil@15 (dashed. lines); Ug=4n/sec, zo = 3 cm.

APPENDIX B

HYDROCARBON VAPOR EMISSIONS FROM A SPILL
OF CRUDE OILONWATER

For our purposes, the ideal oil spill emissions analysis would contain a
detailed listing of hydrocarbon vapor composition, evaporation rates by species
as a function of time, and composition of nonevaporated fractions. Unfortunately,
such studies are, to the author's knowledge, nonexistent. In lieu of more appro-
priate data, we are limited to a breakdown of HC by molecular weight rather than
individual species. According to Dr. Thomas Powers of Exxon Research and Engi-
neering Co., much of the HC vapor which would evaporate from a spill is of the
alkane series, characterized by relatively low reactivity compared to such hydro-
carbon series as olefins and alkynes. 89/

The first step in our analysis is to determine specific gravity of crude oil
by carbon number. Using averages of a number of values obtained from Bland and
-Davidson, we have:

TABLE Al:
CARBON NUMBER VS. SPECIFIC GRAVITY FOR CRUDE OIL 90/

CARBON NUMBER SPECIFIC GRAVITY

3 .536
4 .602
5 .642
6 .666
7 .702
8 .715
9 .718
10 .760
11 .797
12 .791
13 .792
14 .775
15 .798
18 .777
21 .778

From Smith and MacIntyre, we obtain boiling point as a function of carbon number:

282

TABLE A2:
CARBON NUMBER VS. BOILING POINT FOR CRUDE OIL 91/
CARBON NUMBER BOILING POINT ('F)

4 21
5 96
6 146
7 190
8 .236
9 305
10 340
11 370

The points listed in the above tables are plotted in Figure A2, with curves drawn
to fit the respective values.

Calculation of mass fraction content comprised the next step. Distillation
data for both Santa Barbara and Ventura County crudes were obtained from Bland
and Davidson, listing volume percentages and specific gravities of crude frac-
tions for successive cut temperatures. 92/ Averaging the respective values for each
county, the following values were obtai@_ed:

TABLE A3:
FRACTIONAL VOLUME OF COMPONENTS OF LOCAL CRUDE

MEAN
TEMPERATURE TEMPERATURE FRACTIONAL
FRACTION NO. RANGE (OF) (OF) VOLUME

1 77-1122 99.5 .0185
2 122-167 144.5 .0235
3 167-212 1.89.5 .0545
4 217-257 234.5 .0640
5, 237-302 279.5 .0540
6 302-347 324.5 .0460
7 347-392 369.5 .0400
8 392-437 414.5 .0435
9 437-482 459.5 .0470
10 482-@527 504.5 .0555

Thus fraction 1, that whi@ch had vaporized below 122 0F, represented an average of
1.85% of the samples.

Since the tables in Bland and Davidson al'so contained listings of specific
gravities of the fractions, it was possible to determine fractional mass vaporized
at each cut point using the relationship:

283

V SGF
FML = . -
V0 SG0

where FML = fractional mass loss
4'@V=volume vaporized-at each cut point
Vo = original volume of sample
SGF = specific gravity of.fraction
SG0 = specific gravity of original sample
Table A4 contains FML calculations using the above data.

TABLE A4:
FRACTIONAL AND CUMULATIVE MASS LOSS'FOR LOCAL CRUDE OIL SAMPLES

MEAN SPECIFIC FRACTIONAL MASS CUMULATIVE MASS
FRACTION NO'. GRAVITY LOSS LOSS

1 .647 .014 .014
2 .677 .018 .032
3 .725 .046 .078
4 .752 .056 .183
5 .770 .048 .181
6 .790 .042 .223
7 .808 .037 .261
8 .824 .041 .302
9 .837 .045 .347
10 .851 .055 .402

Next, using mean boiling temperatures (Table A3) and specific gravities
(Table A4) for theLten fractions, approximate carbon numbers were approximated
using the two curves in Figure A2.

284

400

-300

LEGEND
200

C. No. vs B.P.
00 0 e
Ul U
13 C. No. vs.S.G.

6. 0

100

0
o
3 s 7 9 11 13 is 17 19
Carbon Number
Figure A2. Carbon Number vS Specific Gravity and B6iling Point.

TABLE A5:
CARBON NUMBERS FROM BOILING POINT AND SPECIFIC GRAVITY RELATIONSHIPS

CARBON NUMBER CARBON NUMBER
FROM FROM
BOILING POINT SPECIFIC GRAVITIES
FRACTION.NO. (C NBP) (CNISG)

1 5.27 5.49
2 6.20 6.46
3 7.73 7.34
4 8.92 8.23
5 10.0 9.11
6 10.0
7 10.89
8 11.77
9 12.66
10 13.54

Using the above results and the mass fraction data in Table A4, the relationship
between carbon number and cumulative mass fraction of the crude was determined. The
results are plotted in Figure A3,

Krieder has published diagrams which show weathering losses of crude oil on
water as functions of time and carbon number. 93/ Curves show the minimum carbon
number present in the oil for several days after the spill; weathering character-
istics are shown for three film thicknesses (0.1, 0.5, and 1.9 mm). Assuming a
thickness of 0.5mm and Kreider's figure, we can plot minimum carbon number present
in the oil as a function of spillage. The results appear in Figure A4. Using these
data in conjunction with the curves in Figure A3 (using CNSG for carbon number less
than 10 and CNBP otherwise), we are able to approximate fractional mass loss as a
function of days of weathering:

TABLE 6:
FRACTIONAL MASS LOSS VS. DAYS OF WEATHERING

MINIMUM
CARBON NUMBER MASS
DAYS AFTER SPILL PRESENT FRACTION.LOST FRACTION REMAINING

1 11.8 .299 .701
2 12.6 .342 .658
.3' 13.1 .365 .635
4 13.7 .409 .591
7 14.3 .450 .550
12 14.8 .485 .515
17 13.1 .510 .490
21 13.2 .525 .475

286

Using the value for one-day age, when .299 of the original mass has been
evaporated (or otherwise lost), let us assume:

- specific gravity of separator liquid .897
- density of water 62.4 lb/ft3
- I gallon water = 8.34 lb
- 1 gallon separator liquid = 7.48 lb
- I barrel separator liquid = 42 gal = 314.3 lb

Thus, after one day, .299 x 314.3 = 94.3 lb per barrel are lost from the surface.
Assuming a reactivity of .30.implies that 28.3 lbs reactive HC are lost. 94/

From the work of Fay, which analyzes the behavior of an oil slick under
calm conditions, it is possible to estimate the size of a slick. 95/ Assuming a
slick length of 1.4 km after one day, we obtain an area of 6.2 km-Tassuming
circular configuration), and thickness of
h = volume of spill
2 77". length2

Using Fay's example (10,000 ton, or 66,380 bbl spill), we obtain a thickness of
0.8 mm after one day and 0.5 mm after 2.3 days. Results of our analysis for both
a 10,000 and.1,000 ton spill are listed in Table A7.

TABLE A7:
EMISSIONS OF HYDROCARBONS FROM AN OIL SLICK
EMISSIONS (tons/hr)
2
SPILL SIZE (tons) DAYS AFTER SPILL AREA (km THC RHC

10,000 1 6.2 92.4 27.7
2 8.0 117.9 35.4
1,000 1 1.3 19.9 6.0
2 1.7 25.4 7.6

The above emission values were divided by the respective slick areas to obtain
fluxes per 1 x' 1 km square, the value used in ARTSIM 'runs as described in . the
section.IMPACT OF HYDROCARBON EMISSIONS FROM OIL SPILLS. According to MIT's ,
Analysis of Oil Spill- Statistics, analysis of marine terminal wills indicates
that probabilities for first-day emissions exceeding those above are about .07%
(10,000 ton spill) and 0.15% (1,000 ton spill). 96/

287

O.S,

0.4-

From CN Table
0
.pq 0'
41
U

0.3. OV 0
000

00 000
00

0.2,
0

From C NSG Table

0
3 7, 8 .9 10 11 12

Figure A3 Carbon Number versus 0,imulative Mass Fraction of Local Crude

U 13

0 5 fo
DAYS AFTER SPILL

Figure A4 Minimum Carbon Number Present in Spilled Oil.

APPENDIX C

POI NT SOURCE DI FFUS ION MODEL P S D M

PSDM was designed to provide estimates of the downwind profile of short-term
concentrations resulting from the emissions of elevated point sources (such as
tall stacks). Ground-level pollutant concentrations along the direction of the
plume centerline can be computed for each of up to 3,840 weather conditions,
includ 'ing eight stability classes, six wind speed classes, and 16 wind direction
classes. The concentrations are calculated at each receptor in a polar grid
system which is defined at specified downwind distances.

SPECIFICATION OF METEOROLOGICAL CATEGORIES

PSDM predicts downwind concentrations expected during a spectrum of stability
classes (including very unstable to stable) by the well known Gaussian diffusion
model for an elevated, continuously emitting point source (see Equation 1). Un-
less otherwise specified, PSDM has five stability classes (for computational
efficiency, the seven Turner classes have been condensed to five): PSDM classes
1-4 correspond to Turner classes A-D, respectively; and, PSDM class 5 combines Turner
categories' E, F, and G. The user may override the default parameters to specify
up to eight stabilities.

PSDM also incorporates default* wind speed classes which vary with stability
category as presented in Table A8. Ganerally, the lightest winds occur with
Stability Class 2, and the strongest with Stability Class 4. Six wind speed
classes can be specified for each stability.
A total of lb default wind direction classes are consideged in PPM calcula-
tions. All are of equal 22 1/2% sector size beginning with 0 -22 112

PSDM also considers up to five mixing depth dategories for each stability
category, wind direction, and wind speed class. This combination of eight
stability categories, six wind speed classes, 16 wind directions, and five mixing
depths gives a total of 3,840 weather conditions for which one- and three-hour
average pollutant concentrations can be calculated.

EQUATION 1:
3Z(0,0,z Q(x9-y9H1 exp exp - 2crZ2 + exp (z+H) 2
2c, 2 2
2,r c, 0- U y 2c-
y z z

where (x,y,z) are the (upwind, crosswind, vertical) components of a Cartesian
coordinate system, such that the receptor point is located at or
vertically above the origin (expressed in units of length), and
the source at the point (x,-yH)

V(0,0 z) is the ground-level pollutant concentration from an elevated point
source at a receptor (0,0,z) @units mass/length3)

*Values used in the program unless.otherwise specified.

290

His the effective height (stack height plus plume rise) of emission
and, therefore, the centerline height of the plume (units length)

Q(x,-y,H) is the source strength.(mass/time)

c7- , cr
ly are dispersion coefficients that are measures of crosswind and
vertical plume spread, respectively, and are functions of downwind
distance and stability (units length)

uis average wind speed (units length/time)

CALCULATION OF SHORT-TERM CONCENTRATIONS

The concentrations are calculated by Equation 1 with y 0. The di-spersion
parameters and are given by
y z
0- = AY * XBY + CY
y BZ
cz =AZ * X + CZ
where the coefficients and exponents AY, BY, CY, AZ, BY, CZ are dependent upon
both stability and downwind distance x as given by the ranges

(1) X2 < x
(2) X1 < x z_ X2
(3) x 4 X1

Default values of the coefficients and exponents are independent of the last
parameter and are those suggested by the ASME (see Table 32).

Three-hour average concentrations are estimated using an option which
simulates the variability in wind direction that typically occurs over this
longer period. The plume is allowed to meander evenly through a sector whose
width is stability-dependent. This sector averaging is specified as a modifi-
cation of Equation 1 as follows:
3HR =@HR Gy * F3HR/x

where

F3HR
tan 12
and e it the sector width.

The default values for-F3HR are:
= 450 for stability 1
0
= 33.75 for stabilities 2, 3, and 4
= 22.5 0 for stability 5

291
20-76658

TABLE A8:
SPECIFICATION OF PSDM ATMOSPHERIC STABILITY AND WIND SPEED'CLASSES

WIND SPEED CLASS
STABILITY DESCRIPTION 1 2 3 4 5
CLASS (mph) (mph) (mph) (Mph) (Mph)

1 Very unstable 2 3 4 5 7
2 Unstable 2 4 6 8 12
3 Slightly unstable 2 4 6 8 12
4 Neutral 4 8 12 20 45
5 Stable 2 4 6 8 12

TABLE A9:
DEFAULT DISPERSION PARAMETERS USED IN CALCULATING O@ AND
z
STABILITY VALUES OF COEFFICIENTS AND EXPONENTS
CLASS AY BY CY AZ BZ Cz

1 0.40 0 91 0. 0.40 0.91 0.
2 0.-36 0 86 0. 0.33 0.86 0.
3 0.32 0 78 0. 0.22 0.78 0.
4 0.32 0.78 0. 0.22 0.78 0.
5 0.31 0.71 0. 0.06 0.71 0.

The wind speed u is specified as an increasing function of.height. The
vertical variations in wi.nd speed are treated using a power law formulation of
vertical wind shear:

Z WEXP
u u0 Z_W I N D
.where u 0 is the reference wind speed (m/s)
.Z is the height above the surface (m.)
ZWIND is the height at which u 0 was measured (m.)
-WEXP'is an array of stab.ility dependent,exponents

TRAPPING

PSDM also considers the-result of the effluent plume being trapped below an
.elevated inversion lid. Conditions beneath the lid vary from very unstable to
neutral stabilities. Lidded conditions require.a modification of Equation 1.

To account for the lid, image sources are created above the lid and below
the ground which add to the total concentration. The height of-the inversion is
set at five specified heights. If.the rise of the poi.nt source plume is at least
ten%meters (or some other specified distance) higher than inversion height, the

292

plume is considered to pass through the inversion into stable air and disperse
only.gradually to the ground. If the calculated plume rise is less than ten
meters above the inversion height, the plume is considered trapped by the inver-
sion and the trapping model is used.

PLUME RISE

PSDM uses the most recent Briggs plume rise equations in forms which depend
on stability. The formulation includes calculation of both transitional and
equilibrium plume rise.

For neutral and unstable conditions (PSDM stabilities 1-4):
h 1.6F 1/3 x 2/3 x z, 3. 5x.*
u
1.6F 1/3 (3.5x*) 2/3 x > 3.5x*

where h = plume rise (m.)
F = buoyancy flux (m 4/sec3
x* = downwind distance at which atmospheric turbulence dominates entrain-
ment in plume rise (m.)
X* = 14F 5/8 for F-55m4/sec 3
34.49F 2/5 for F 55m4/sec3
3.5x* = downwind distance at which plume reaches equilibrium level (m.)
For stable conditions (PSDM stability 5):
r 1/3 2/3 u 112
A h x < 2.4 s
u
2.9 _L_l 3 x. ;@ 2.4 U 112
U*s s

where s = stability parameter based on atmospheric lapse rate
= VPTG*G/TA

where VPTG = rate of change of potential temperature with distance
(default value .01370K/m)
G = gravitationa 1 acceleration (9-8 m/sec 2
TA = ambient air temperature (default 2900K)
For a calm atmosphere (-u < 1.37 m/sec),
6 h = 5.017 1/4 S_ 3/8

293

THE EFFEtTS'OF'TERRAIN

The PSDM program accounts for terrain elevations by permitting the plume to
be lifted a fraction, TER, of the difference between the height of the receptor
(the point on the ground for which the concentration is being computed) and the
height of the stack base, with the additional restriction that the plume shall
always be at least 1-TER of the height above the ground that it would be if there
were no topography. Default value of TER is .50. The simultaneous consideration
of both the plume rise as a function of downwind distance and of the topography
surrounding the point source provides a realistic simulation of the downwind
transport of effluent released in areas characterized by irregular terrain.

294

FOOTNOTES

1. EPA, Compil tion of Air Pollution Emission Factors, AP-42, Appendix B,
part B, 2nd ed.

2. Energy Resources Conservation and Development Commission, Facility
Siting Division, Compilation of Air Pollution Control Regulations and Standards
(Draft), June 8, 1976, p. 22.

3. Sedway/Cooke, Land and the Environment;-Planning in California Today,
Planning and Conservation Foundation, (William Kaufmann Inc.) pgs. 39-40.

4. 42 U.S.C.A.- � 1857c-9.
5. 40 C.F.R. � 51.18.
6. 42 U.S.C.A. � 1857c-9-

7. State of California Air Resources@ Board, ARB Fact Sheet 27 (revised),
March 10, 1976.

8. Air Resources Board Resolution 76-39, October 3, 1976.

9. R. A. Nordsieck, Air Quality Impact Analysis for the Santa Barbara County
(California) Regi-onal Transportation Plan_, Report P-1920F, Environmental Research
and Technology, Inc., Santa Barbara, California 1976.

10. 43 U.S.C.A. � 1334(a)(1).

11. 493 F.2d 141 (9th Cir. 1973) at 145.
12. 30 D.f.R. � 250.10.
-13. 43 U.S.C.A. � 1333(a)(1).
14. EPA Regional Counsel Opinion, #293, September 15, 1975.

15. Brown v. EPA, 521 F.2d 827 (9th Cir. 1975).

16. Memorandum from Philip K. Verleger, McCutcheon,.Black, Verleger & Shea,
to R. L. O'Connel, Director, Enforcement Division, EPA, October 1, 1976.

17. Personal communication to Dave Calfee by Jim Grove EPA, Region IX,
April, 1977.

18. Memorandum of G. William Frick, General Counsel to Rebecca W. Hanmer,
Director, Office of Federal Activities, dated September 23, 1976.
19. 43- U.S.C.A. � 1333(a)(2).,
20. Memorandum from Philip K. Verleger, loc. cit.

21. Ibid.

22. State.of California Air Resources Board, Plan Development Program for
an Air Conservation Program for California, February, 1977, revision, p. 16.

295

23, California Air Resources Board, "Emissions and Air Quality Assessment,"
Report No,. ARB/EP-76001, April, 1976, p. 4.26.

24. Ibid.

25, Ibid.

26. Ranzieri, Andrew J., et al. "Examination of Regional Photochemical Models
From a User's View Point," Presented at the Air Quality Workshop in Washington,
D.C., October 22-24, 1975, State of California, Department of Transportation,
Division of Construction and Research Transportation Laboratory, p. 5.

27. Ibid., p. 5-6.

28. California Air Resources Board,-p. 4.29-4.30.

29. California Air Resources Board, "Introduction to Air Quality Simulation
Modeling," Research Division, Air Quality Modeling Section, October, 1976, p. 25.

30. Ibid., p. 25-26.

31. Ranzieri , p. 8-9.

32. Ibi-d., p. 13.

33. Ibid., p. 9-10.

34. Ranzieri, p. 11-12.

35. Ibid., p. 15.

36. Ibid., p. 16.

37. Ibid., p. 17.

296

FOOTNOTES.

38. F. E. Gallison, W. L. Faith, and L. L. Maga, Air Pollution in Ventura@
County, County of Ventura Health Department and California Department of Public
Health, 1966.

39. Oil and Gas Development in the Santa Barbara Channel Outer Continental
Shelf off California, Final Environmental Statement, United States Geological
Survey, March 1976.

40. 'J. H. Smith et al., Air Quality Impact for Proposed Highway Widening
Near Ojai,, Stanford Re'se-arch 'Institute,.Menlo Park, California, 1974.

41. J. J. R. Kinney, Climate of the South Central.Coast Air.Basin, California
Air Resources Board, Sacramento, California, 1975.

42. Glenn T. Trenwartha, An Introduction to Climate, McGraw-Hill, New.York,
1968.

43. Smi th et al . , op. ci t.

44. Gallison et al., op. cit.

45. Southern California OCS Oil Development: Analysis of Key Issues, Environ-
mental-Science and Engineering, University of California at Los Angeles, 1976.

46. J. Leach, California Air Resources Board, in Onshore Impact of Offshore.
Southern California OCS Sale 35, Office of Planning and Research., Sacramento,
California, January.1976, pp. 6-8.

47. Kinney, op. cit. T. O'Neill, Santa Barbara Channel Tidelands Production.
Scenarios, 1976-1997, unpublished memorandum, Office of Planning and Research,
Sacramento, California, November 1976.

48. Onshore Impact of Offshore Southern California OCS Sale 35, Office of
Planning and Research, Sacramento, California, January 1976.

49. J. Laird, Santa Barbara County Ai,r Pollution Control District, personal
communication, October 1976.

50. Leach-, loc. cit.

51. Compilation of Air Pollutant-Emission Factors, 2nd edition, U.S. Environ-
mental Protection Agency, Research Triangle Park, North Carolina, 1975.

52. Leach, loc. cit.

53. J. F. MacKenzie and C. T. Rau (Exxon Research and Development Corporation),
"Gaseous Hydrocarbon Emissions During Loading of Marine Vessels," 69th Meeting of
the Air Pollution Control Association, Portland, Oregon, June-July,.1976.

54. A. Lind, unpublished memorandum, Office of Planning and Research, San
Francisco., California, November, 1976.

55. Leach, loc. cit.

297

56. A. Lind, Air Quality Scenario, unpublished memorandum, Office of
Planning and Research, San Francisco, California, November, 1976.

57. O'Neill, op. cit.

58. K. L. Schere, U.S. En vironmental Protection Agency, personal communica-
tion, 1975.

59. Dr. Alan C. Lloyd, Environmental Research & Technology, Inc., personal
communication, 1976.

60. O'Neill, op. cit.; O'Neill, Santa Barbara Channel OCS Oil and Gas
Production Scenarios and, Lind, Air Quality Scenario (op. cit.).

61. R. A. Nordsieck, Air Quality Impact Analysis for the-Santa Barbara
County (California) Regional Transportation Plan, Report P-1920F, Environmental
Research & Technology, Inc., Santa Barbara, California, 1976.

62. Schere, op. cit.

63. Nordsieck, op. cit.

64. Schere, op. cit.

65. Leach, op. cit.

66. Lind, unpublished memorandum, op. cit.

67. Ibid., see also Nordsieck, op. cit.

68. Lind, op. cit.

69. Ibid.

70.. Compilation of Air Pollutant Emission Factors, passim.

71. Schere, op. cit.

72. Southern California OCS Oil Development: Analysis of Key Issues, passim.

73. P. R. Harrison and S. J. Maas, Monitoring of Natural Seeps in the Santa
Barbara Channel off Coal Oil Point, Meteorology Research, Inc., March 1976.

74. Ibid.

75. Lloyd, op. cit.

76. Leach, op. cit-.

77. Gallison et al., op. cit.

78. A. Lind, memorandum to D. Calfee and T,. O'Neill, Office of Planning and
.Research, San Francisco, California, July 1976.

298

79. Lind, unpublished memorandum, passim.

80. Monthly and Annual Wind Distribution by Pasquill Stability Classes,
Point Mugu NAS, 1960-64, National Climatic Center, Asheville, North Carolina,
1974.

81. 'Southern California OCS Oil Development: Analysis of Key Issues, passim,
and Leach, op. cit.

82. Lind, unpublished memorandum (op. cit.).

83. Monthly and Annual Wind Distribution by Pasquill Stability Classes, Point
'Mugu NAS, 1960-64, passim.

84. Compilation of Air Pollutant Emission Factors, passim.

85. Lind,.unpublished memorandum, passim.

86. Final Report on the Las Flores Canyon Baseline Air Quality/Meteorology
Study, No rth American Weather Consultants, Goleta, California, March 1976.

299

FOOTNOTES, APPENDIX I

87. A. K. Blackadar, "The Vertical Distribution of Wind and Turbulent
Exchange@ in a Neutral Atmosphere," Journal of Geophysical Resources, 67,
pp. 3095-3102, 1962. B. A. Egan and J. R. Mahoney, "Applications of a Numerical
Air Pollution Transport Model to Dispersion in the Atmospheric Boundary Layer,"
.Journal-of Applied Meteorology, 11, pp. 1023-1039, 1972. K. W. Ragland and
J. J. Pe rce, "Boundary Layer Model for Air Pollutant Concentrations Due to
Highway Traffic," Journal of Air Pollution Control Association, 25, pp. 48-53,
1975. D. F. Fulle, personal correspondence, 1975.

-88. F. Pasquill, Atmospheric Diffusion, John Wiley & Sons, New York, 1974.

FOOTNOTES, APPENDIX II

89. Dr. Thomas Powers, Exxon Research and Engineering Co., personal communi-
cation, December, 1976.

90. W. F. Bland and R. L. Davidson, Petroleum Processing Handbook, McGraw-
Hill, New York, 1967.

91. C. L. Smith and W. G. MacIntyre, "Initial Aging of Fuel Oil Films on
Sea Water," Proceedings of Joint Conference on Prevention and Control of Oil
Spills, Washington, D.C., 1971.

92. Bland and Davidson, op. cit.

93. R. E. Kreider, "Identification of Oil Leaks and Spills," Proceedings of
Joint Conference on Prevention and Control of Spills, Washington, D.C., 1971.

94. J. C. Trijonis and K. W. Arledge, Impact of Reactivity Criteria on
Organic Emission Control Strategies in the Metropolitan Los Angeles AQCR, TRW,
Inc., March, 1975.

95. J. A. Fay, The Spread of Oil Slicks on a Calm Sea, Massachusetts Institute
of Technology, August, 1969.

96. Massachusetts Institute of Technology, 1974.

300

GLOSSARY OF AIR POLLUTION TERMS
ADVECTION. Transport of material (e.g., pollutants) through the atmosphere
by winds.

AIR BASIN. A region in which the air quality is determined by the meteorology
and emissions within it, with minimal influence on and impact by contiguous regions.
In California, the 14 air basins have boundaries- established by the Air Resources
Board. While the above criterion is the major consideration, the boundaries may be
the borders of counties if such borders are close to.the boundary of the natural air
basin.

AIR.MONITORING. Sampling for and measuring of pollu -tants present in the
atmosphere.

AIR PARCEL. Any air mass assumed to be relatively independent of mass inter-
changes with its surroundings.

AIR POLLUTION CONTROL BOARD (APCB). The board of directors for the APCD: the
County Board of Supervisors in single county APCDs; in multi-county APCDs, it con-
sists of members from each county's Board of Supervisors, except special cases such
as_BAAPCD (Bay Area APCD)-.

AIR POLLUTION CONTROL DISTRICT (APCD Local governmental agencies on the
cqunt@ -1evel with the legislative authority to adopt and enforce all rules and
regulations necessary to control.non-vehicular sources of air contaminants.

AIR POLLUTION CONTROL OFFICER (APCO). The appointee of the local APCD with the
duties of implementing and enforcing all rules and regulations as prescribed by the
APCD.

AIR QUALITY MAINTENANCE AREA (AQMA). Areas which, due to current air quality
and/or projected growtF -rates, may have the potential for exceeding.any national
ambient air quality standard within the next 20 years. These areas were identified
pursuant to federal regulations (Federal Register, June 18, 1973) and are contained
in ARB's Revision 5 of State Implementation Plan.

AIR-QUALITY MAINTENANCE PLAN (AQMP)., A comprehensive plan to assure the
achievement and/or maintenance of the national air quality standards through the
long term (20-25 years), The plans are to be formulated at the local level and will
integrate direct source controls', land use plans, and transportation strategies
which will- be implemented at the state'and local level to achieve and maintain the
air quality standards. AQMPs are required by the Clean Air Act and subsequent EPA
regul ati ons.

AIR QUALITY STANDARDS. A quantification of allowable levels of air pollution.
There are two types of National Ambient Air Quality Standards (NAAQS)--the primary
standards and the secondary standards. (See National Prima@y Standards and National
Secondary Standards,) Under provision of the ord-Carrell Act, the State Air-
Resources Board is required to set state air quality standards. However, since there
,are no specified dates set for attainment of the standards, the state air quality
standards are.essentially air quality goals.

ALKANE (PARAFFIN) SERIES. A hydrocarbon series characterized by single covalent
bonds and hence relatively low reactivity. Examples: methane, propane, octane.

301

ARTSIM MODEL. [email protected] and Transport SIMul-ation, a semi-Lagrangian
model in which chemical and photochemical reactions and vertical diffusion mechanisms
are used in calculating air pollutant concentrations within a moving air parcel.

BACKGROUND LEVEL. Amounts of pollutants present in the ambient air due to
naturaT -sources. Examples, marsh gases, pollen, windblown dust.

BOUNDARY CONDITIONS. The values of a variable at each point along the boundaries
of a region for a single analysis.

BOUNDARY LAYER. The lowest levels of the earth's atmosphere, within which most
air pollutants are confined.

CARBON MONOXIDE (CO). A colorless, odorless, toxic gas produced by the incom-
plete combustion of carbon-containing substances. One of the major air pollutants,
it is emitted in large quantities in the exhaust of gasoline-powered vehicles.

DIFFUSIVITY. A constant of proportionality that relates the flux of a component
of a non-uniform fluid to the gradient of concentration of that component. Value of
the diffusivity depends on molecular or turbulent disturbances in the fluid mixture.

DISPERSION MODEL. A mathematical representation and solution of the physical
processes that result in the spread of pollutants in the atmosphere. The phenomenon
of direct interest in predicting the dispersion of pollutants is turbulent diffusion.
Consequently, dispersion models are sometimes called diffusion models. However,
turbulent diffusion and diffusion models are misnomers. The phrases refer to the
spreading of a cloud of particles in a turbulent fluid at a rate many orders of mag-
nitude greater than that from molecular diffusion alone. The spreading is really
not due to a "diffusion" phenomenon such as results from molecular collisions but
rather is a result of the rapid, irregular motion of lumps of fluid (called eddies)
in a turbulence.

EMISSIONS FACTORS. An expression of the estimated emissions of air pollutants/
unit time/activity. Examples-of activities are low density residential land use,
vehicle miles traveled for a certain model and year automobile or truck, and landing-
takeoff cycles of aircraft. Emissions factors are being developed by the Environmen-
tal Protection Agen6y and the Air Resources Board for use in the preparation of emis-
sions inventories and emissions projections for p.lanning purposes.

EMISSIONS INVENTORY. An inventory of the spatial distribution of sources of
air polluting emissions and pollutant types and quantities from each source within
a given geographic area for a given time period. The locations of emissions from
stationary sources and mobile sources are presented separately in an emissions
inventory.

EMISSIONS RATE. The mass of specific pollutants emitted into the atmosphere by
one or more sources within a certain time period (e.g., lbs/hr).

EMISSIONS STANDARD. The maximum amount of a pollutant that is permitted to be
disch@-rged from a polluting source; e.q., the number of pounds of dust that may be
emitted from an industrial process.

EULERIAN GRID CELL. A unit of an analysis grid that is fixed in space.

FLUX. The rate per unit area at which material or energy moves across a plane
perpe@_dicular to the flow.

302

GAUSSIAN MODEL. A pollutant dispersion model based on the Gaussian concen-
tration. equation, which assumes a constant fractional decrease in concentration
per unit distance from a stationary or moving center of dispersion.
.HYDROCARBON (HC1. Any of a vast family of compounds containing carbon and
hydrogen in various combinations; found especially in fossil fuels. Some of the
hydrocarbon compounds are major air pollutants; they may be active participants
in the photochemical process or carcinogenic.

INVERSION. The phenomenon of a layer of warm air lying over and trapping cooler
air below. A special problem in areas having large sources.of emissions because the
contaminating substances cannot be dispersed through the layer of warm air, and high
levels of air pollution result.

LAGRANGIAN ANALYSIS. A modeling type which involves the behavior and character-
istics.of an air parcel moving along a trajectory through the atmosphere.

MIXED LAYER. Layer of air near the ground where turbulent mixing of pollutants
occurs. It is limited by an inversion base, if one is present.

MONITORING. The sampling and measuring, on a continual or continuous basis,
of ai-r pollutants.

NATIONAL AMBIENT AIR QUALITY STANDARDS (NAAQS). Standards for air quality as
set by the EPA Administrator, prescribei in terms of maximum concentrations permis-
siblefor various pollutants and averaging times.

NATIONAL PRIMARY STANDARDS. The levels of air quality necessary, with an
adequate margin of safety, to protect the pu 'blic health. Each state must attain the
primary standards no later than three years after that state's implementation plan
is approved by the Environmental Protection Agency (EPA).

NATIONAL SECONDARY STANDARDS. The levels of air quality necessary to protect
the public welfare from any known or anticipated adverse effects of a pollutant.
Each state must attain the secondary standards within a "reasonable time" after
implementation plan is approved by the EPA.

NEW SOURCE PERFORMANCE STANDARDS (NSPS). Regulations promulgated by EPA that
establish the,maximum permissible emission levels from certain types of new sources.

NITROGEN OXIDES (NOx). Gases formed from atmospheric nitrogen and oxygen when
combustion takes place under conditions of high temperature and high pressure; con-
sidered major pollutants. Also formed in industrial processes, such as the produc-
tion of nitric acid.

NO SIGNIFICANT DETERIORATION. Pursuant to a court decision, EPA adopted regu-
lations for preventing significant deterioration of air quality in those areas of
the states where air quality is at levels better than the NAAQS. The regulations
apply only to particulate matter and sulfur dioxide.

OFFSHORE STORAGE AND TERMINAL FACILITY (OS&T). An OS&T is a permanently moored
vessel used fo-r the storage of crude oil pending arrival of a tanker to transport the
oil to its destination. An OS&T may be a modified tanker (as proposed by Exxon for
the Santa Ynez Unit) or a barge-like vessel. Once its usefulness has .ended, an OS&T
may be moved and re-used elsewhere.

303

OLEFIN SERIES. A hydrocarbon series characterized by a double bond between
two carbon atoms, resulting in relatively high reactivity. Examples: ethylene,
propylene.

OXIDANT. Substances in the air such as ozone which make available oxygen or
oxygenated compounds for chemical reaction. Oxidants may be formed from the reac-
tion of certain reactive hydrocarbons and nitrogen dioxide, under the influence of
sunlight.

OXIDE. A compound of two elements, one of which is oxygen.
OZONE (2-
a. A pungent, colorless, toxic gas. As a product of the photo-
chemical process, it is a major air pollutant.

PARTICULATE MATTER (PM). A particle, or particles, of solid or liquid matter
such as soot, dust, aerosols, fumes, and mists.

PARTS PER MILLION (PPM). A volumetric measure of concentration in which is
given the number of parts of a specific pollutant in a million parts of air.

PLUME. The spreading pollutants emitted by a fixed source, such as a smokestack.

POINT SOURCE. A stack of other highly localized pollutant source. Contrasted
to an area source.

POINT SOURCE DIFFUSION MODEL (PSDM). ERT's Gaussian-type model designed to
provide estimates of downwind short-term concentrations of pollutants emitted by
surface-based or elevated point sources.

PRIMARY POLLUTANTS. Pollutants emitted directly from sources.

PURGING. The process of flushing cargo tank atmospheres with inert gas for
the purpose of reducing the concentration of hydrocarbon gas. Thereby, pollutants
which are dispersed in the cargo tank gases are released into the atmosphere.

RAWINSONDE. An electronic device carried aloft by a buoyant balloon to
measure temperature, dewpoint, pressure, and winds at various levels in the earth's
atmosphere.

REACTIVE HYDROCARBON (RHC). A hydrocarbon that readily combines with radicals
and thereby contributes to ozone production.

RECEPTOR. Commonly used in air quality discussions to describe any human,
animaT, -plant, or material that can be adversely affected by air pollutants.

SECONDARY POLLUTANTS. Pollutants formed by chemical and photochemical
reactions in the atmo@_p_here.

SIMULATION MODEL. A mathematical description of real physical and/or chemical
processes. The responses of the model to input variations are analogous to those
of the real processes.

SOURCE REVIEW. A general term used to describe any one of a number of specific
reviews that need to be conducted on proposed facilities that will produce pollutants.
The review is designed to determine the acceptability of the source with regard to

304

types and amounts of pollutants that will be produced as the existing pollution
control.s and/or strategies within the area of impact.

STABILITY. The relative amount of turbulent mixing which occurs in the
atmosphere; a function of temperature differences; wind shear, and other metero-
logical parameters. Higher stabilities (i.e., more stabl,e-atmospheric character-
istics) imply less tu'rbulen@ mixing.

STANDARD OF PERFORMANCE. An emi-ssion limitation imposed on a particular
category of pollution sources, either by EPA, the state, or the local APCD.
Limitations may take the form of emissions standards or of requirements for spe-
cific operating procedures.
SULFATES. Principally the sulfur oxides S03, HS04, and H2SO4 (not S02) that
are generally found as-aerosol's.and particulates. Major sources are power plants,
refineries, chemical industry,processes, and recently demonstrated to be a by-
product of the catalytic converter installed on new automobiles.

SULFUR OXIDES (SOx). Pungent, colorless gases formed primarily by the com-
bustion of foss@il_fuels containing sulfur; considered major air pollutants. Sulfur
oxides may damage-the-respiratory tract as well as vegetation.

SURFACE FLUX. The rate per unit area at which some quantity passes through or
is emitted from the surface.

TRAJECTORY The path taken by an air parcel as it is advected by the wind;
calculated directly.(e.g.., tracking of balloons) or indirectly (interpolation of
wind station data).

TRANSPORT. Generally used in air quality discussions to describe the physical
phenomenon-whereby pollution is carried from the site of emission to another site.

UNIVERSAL TRANSVERSE MERCATOR (UTM) System. An arbitrary system of east-west
@and north-south lines- spaced one kilometer apart which intersect to form one-square-
.kilometer squares when.-superimposed on the earth's surface.

VENTING .(or BREATHING). Hydrocarbon emissions escaping from cargo tanks from
either tFe--ullage-hatches or pressure-vacuum valves. It is a consequence of natural
phenomena such as barometric pressure changes, ambient temperature changes., and
vapor growth.

VEHICLE MILES-TRAVELED (VMT). A term.used,to describe the number of.miles
traveTe-dby vehicles in a specified area-during a given time.

WIND SHEAR. The spatial variation of wind velocity.

305

CHAPTER 16

SENSITIVE RESOURCES:
INVALUABLE VALUES

The Southern California Bight with its irregular coastline, its submarine
ridges rising steeply out of deep basins, and its bordering offshore islands,
provides habitat for a multitude of marine species. The Channel Islands and the
shallow offshore banks are also sufficiently isolated from the mainland and from
one another to permit the development of numerous endemic populations of marine
flora and fauna. This isolation also provides a refuge for over 80 species of
resident and migrant seabirds, as well as breeding and pupping areas for five
species of seals and sea lions. l/
The development of leases sold in the three previous OCS sales could result
in a variety of conflicting resource uses of the marine and coastal environments
of southern California. Adverse effects on marine organisms, seabirds, endangered
wildlife species, recreational resources, and other environmental attributes could
occur as a result of chronic and catastrophic discharges of oil and other toxic
substances, modification and destruction of habitat during pipeline construction,
and the alteration of natural conditions and unique ecological sites which may
result from human disturbance, structures, and other development pressures. For
all species, greatest concern is for the possible impact of some phase of petro-
leum development on.scarce, unique, or otherwise critically important habitats
upon which they depend.

This inventory of sensitive resources has been compiled for the five affected.
counties' coastlines and for the eight offshore islands in order to help planners
@order priorities and devise strategies for protecting these resources. Three
categories of critical resources are discussed with regard to their environmental
and economic value: (1) officially designated environmentally sensitive areas;
(2) other habitat areas of particular value and/or vu.lnerability; and, (3) areas
of economic and recreational importance.

Areas in each category were chosen for inclusion on the basis of two criteria:
biological sensitivity and geographical vulnerability. In order to be considered,
each resource or habitat type had to be sensitive to oil development as well as
potentially threatened by that development.

The accompanying maps indicate.the location of sensitive resources, illus-
trating where the greatest concentrations of critical habitats and recreatio.nal
activity occur.

21-76658 307

The base maps for the inventories are the coastal portions of the standard
USGS 7-1," quadrangles, 1:24,000, reproduced at 37% of the original to a scale of
1:62,500 approximately. The islands were initially scaled at 1:62,500; they are
also reproduced at 37% of the original, to a scale of 1:165,000.

CRITICAL HABITATS

Certain habitat types have been repeatedly identified in the literature as
being sensitive to disturbances from petroleum development activities. Spilled
oil, in particular, has a great potential for damaging pinniped and seabird
rookeries, wetlands, rocky intertidal areas, kelp beds, and offshore reefs. The
biological sensitivity and geographical vulnerability of each of these important
habitats found in the Southern California Bight are discussed below.

P I N N I P E D R 0 0 K -E R I E S A N D M A J 0 R H A U L - 0 U T
A R E A S

According to the Marine Mammal Commission, the Channel Islands and surround-
ing waters support one of the world's most diverse assemblages of marine mammals.
Historically,,seal and sea lion populations in the Southern California Bight were
much larger. Pinnipeds once bred in great numbers along the southern California
mainland coast and still do in areas north of Point Conception where little or no
human activity is present. Human,activity in southern California has disturbed
these marine mammals to such an extent that th'ey no longer breed at their previously
established coastal rookeries. 21 Today, seals and sea lions breed and pup almost
exclusively on the Channel IslaFds.

The most-thorough study to date of the marine mammals inhabiting the southern
California waters and offshore i'sl-ands is being conducted under the auspices of
the Bureau of Land Management baseline studies program, by contract with scientists
.at the University of California, Santa Cruz, and Irvine. The six-month progress
report characterized the pinniped population as follows:
Many thousand seals and sea lions are found in the Southern California
Bight either as year-round,residents or as seasonal transients. Major
.populations of the northern elephant seal, Mirounga augustirostris, the
.California sea lion, Zalophus californianus, and the harbor seal, Phoca
,.Nitulina, pup and breed each year on the rocks and beaches of the Channel
Tslands. In addition,-the northern fur seal, Callarhinus ursinus, and
the:Stel-ler sea lion, Eumetopias jubata,.have the southernmost extension
of their breeding range in these islands. With the presence of rare
Guadalupe fur seals,-Arctocephalus townsendi, an endangered species, the
.Southern California Bight possesses,the largest and most diverse pinni-
ped community in temperate waters. 3/

From.census data contained in the above report, major breeding and haul-out
areas have been mapped. Highest densities of animals are found on San Mi.guel
Island, where a survey at the peak of-the sea lion breeding season found 15,337
pinnipeds, primarily clustered on the west end. San Miguel Island and its as.so-
ciated rocks form the most important pinniped habitat in southern California. Six
species of seals and sea lions inhabit the island, and five breed there.
.According to the U.S. Fish and Wildlife Service, San Miguel Island has an ideal
environment for pinnipeds because of its climate and the configuration of its low,

308

sandy beaches. Because it is located where warm and cold currents meet, the
island demarcates the southern range of northern species of pinnipeds and the
northern range of southern species.

San Nicholas Island is the second largest hauling-out ground, followed by
Santa Barbara and to a lesser extent, San Clemente islands. San Nicholas and
Santa Barbara islands support breeding populations of the northern elephant seal,
the California sea lion, and the harbor seal. A very large rookery of
California sea lions is found on the western side of San Clemente Island, as well
as a smaller number of northern elephant seals.

Pinnipeds are also found on Santa Rosa, Santa Cruz, Anacapa, and Santa
Catalina Islands, but not in the numbers or concentrations found on San Miguel,
Santa Barbara, San Nicholas, and San Clemente.

According to Linstedt-Siva, several mainland sites are used by harbor seals
as haul-out grounds and possibly breeding grounds. 4/ These remote beaches
appear to be used primarily at night, and have larg@_Iy escaped detection. The most
important site identified to date is at Burmah Beach where up to.165 individuals
have been observed.

The maps indicate where concentrations of 'pinnipeds were found consistently
during the first six months of the marine mammal/bird baseline study, including
the scattered mainland sites. A final report based on the entire first year's
effort will be released imminently and will include an annual cycle for each
island for each species, behavioral information, at-sea census data, and estimates
of the total breeding population of each species, as well as distribution and
density of pinnipeds on land. No attempt is made, on the maps at the end of this
chapter, to represent such a degree of specificity. Rather, each symbol indicates
geographically defined areas where pinnipeds were consistently,observed in close
aggregations.

These areas are considered extremely sensitive according to the EIS for OCS
Lease Sale #35, which stated that.:

The greatest danger to marine mammals is disturbance of pinnipeds from
drilling operations and from platform construction or onshore separation
and storage facilities on the islands near breeding and hauling-out
areas. Activities associated with platform installation, exploratory
drilling and production operations off San Miguel and Santa Barbara is-
lands could cause significant reductions in sea bird populations and the
potential elimination of sea lions, fur seals, and harbor seals from
their principal breeding area in southern California. The ultimate out-
come of rookery abandonment is the elimination of pinnipeds from southern
California waters. 5/

It was further concluded that drilling activities within three miles of
rookeries were potentially dangerous to pinniped populations, and the following
alternative was offered:

No offshore structure, either temporary or permanent, will be placed
closer than six (6) statute miles from the shorelines (mean high tide
level) of San Miguel and Santa Barbara islands in order to provide a
minimum buffer zone for pinniped and sea bird rookeries located on these
islands. This restriction includes exploratory drilling structures. 6/

309

The Bureau of Land Management considered six miles a minimum requirement in
order to reduce the possibility of ship traffic and human activity interfering
with the normal behavior of the sea birds and pinnipeds. That distance would
also provide more time to set up containment equipment before an oil slick
could reach the shore.

Although little is known about the sensitivity of pinnipeds to petroleum,
it is acknowledged that petroleum is more debilitating to fur seals than to
sea lions.or elephant seals because of the fur seals' pelage. 7/

Unquestionably, the greatest'known danger to pinnipeds is disturbance during
critical periods in their life cycles @, breeding, pupping, and nursinq_.
Thus, in the event that an oil spill should reach the shore of the rookeries, the
presence of spill cleanup crews and equipment could conceivably cause more damage
to the pinnipeds than the spill itself.

In commenting on OCS Lease Sale #35, the,U.S. Fish and Wildlife Service also
recommended that an ecological buffer zone should be established around the
Channel Islands, especially San Miguel and Santa Barbara-, in order to protect them
from the possible adverse effects of exploration and development. 8/

The Marine Mammal Commission similarly urged that further exploration or
leasing in the Channel be delayed until environmental baseline studies are
completed and a better understanding is reache'd of the potential for OCS
activities to harm the marine mammal population. The Commission also
recommended that the three-mile buffer zone around San Miguel, Santa Rosa, and
most of Santa Cruz Islands be extended to six miles, in order to protect pinniped
habitats. 9/

Tracts southwest of San Miguel were withdrawn from OCS Lease Sale #35, but
tracts adjacent to Santa Barbara Island were offered and subsequently leased.
More tracts adjacent to Santa Barbara Island will be included in BLM's environ-
mental impact statement for OCS Sale #48. Tracts north and south of the Northern
Channel Islands are also included, as can be seen from the map following. Tracts
.in the same area, immediately adjacent to the three-mile state boundary were
leased by BLM in 1968, and exploration has taken place in the tracts north of
San Miguel Island.

As the intensity of petroleum development activity builds in offshore
California waters as a result of Lease Sale #35 and the pending Lease Sale #48,
a minimum of six miles must be established and maintained as a buffer zone
between important pinniped breeding grounds and all forms of petroleum-related
activity.

R A R E A N D E N D A N G E R E D S P E C I E S H A B I T A T

Rare and endangered animals are at the limit of their tolerance as a result
of human disturbance and habitat destruction.* Minimization of further encroach-
ment on areas essential for their continued survival is the aim of endangered species
legislation, both federal and state. Legal support for the preservation of threatened
species is provided by the California Department of Fish and Game and the U.S. Fish
and Wildlife Service (U.S. Department of Interior).

Major habitats of species on the federal and state t hreatened lists are indicated
on the maps at the end of this chapter.
310

The State's Endangered Species Act, passed by the Legislature in 1970,
defined rare and endangered wildlife and gave the Fish and Game Commission
authority to designate which animals in California are endangered.

These terms have been defined by the Legislature:
Endangered - "is an animal of a species or subspecies of bird, mammal,
fish, amphibian, or reptile, the prospects of survival and reproduction
of which are in immediate jeopardy from one or more causes, including
loss of habitat, change in habitat, over-exploitation, predation, compe-
tition, or disease."

Rare - "is an animal of a species or subspecies of bird, mammal, fish,
amphibian or reptile that, although not presently threatened with
extinction, is in such small numbers throughout its range that it may
be endangered if its environment worsens."
It is unlawful to take, possess,or sell an animal designated as endangered or
rare.

Also in 1970, the Legislature passed the California Species Preservation
Act, directing the Department of Fish and Game to inventory all threatened fish
and wildlife, and report to the Governor and the Legislature every two years on
the status of these animals. California was the first state to provide protec-
tive legislation prohibiting the importation, taking, possession, and sale of
endangered and rare species.

Of 49 rare and endangered species statewide, nine are found in the Southern
California Bight. 10/ The following six species rely on either the mainland coast
or the islands for@_habitat:

Island Fox, Urocyon littoralis, rare

Guad alupe Fur Seal, Arctocephalus townsendi, rare

California Brown Pelican, Pelicanus occidentalis californicus, endangered

California Least Tern, Sterna albifrous browni, endangered

Light-Footed Clapper Rail, Rallus longirostris levipes, endangered
Belding's Savannah Sparrow, Passerculus sandwichensis beldingi, endangered

Habitats of the following three endangered species are less well-known due
to infrequent sitings as their numbers have declined.-drastically in recent years:

California Black Rail, Laterallus jamaicensiscoturniculus, rare

American Perigrine Falcon, Falco peregrinuis auatum', endangered

Southern Bald Eagle, Haliaeetus leucocephalus leucocephalus, endangered
These three species once nested extensively on the mai-nland toast and/or the
Channel Islands, but the location of the few remaining nesting sites for each is
now a.well-kept secret. For this reason, they are not included on the maps.

311

The California Department of Fish and Game has recommended that critical
habitats essential to the survival of these animals be placed under public
stewardship or protected by law.

The federal Endangered Species Act of 1973 strengthened earlier legislation
and extended federal authority over migratory and resident as well as foreign
species of plants and animals declared threatened by the Secretary of the Interior.
The law makes it a federal offense to take endangered or threatened wildlife and
requires all federal agencies to use their authorities to carry out programs
for conservation of endangered and threatened species and to take action to assure
that their programs do not jeopardize the continued existence of endangered or
threatened species or result in the destruction or modification of critical
habitat.

Species on the federal endangered and threatened list, whose habitat could
be affected by oil and gas development,are the following:
California Brown Pelican, Pelicanus occidentalis californicus

Light-Footed Clapper Rail, Rallus longirostris levipes

California Least Tern, Sterna albifrous browni

The following species on the federal list are found in the Southern California
Bight but were not mapped because of uncertainty about habitat areas and their
potential to be affected by petroleum development. ll/

Pacific Right Whale, Eubaleaua spp., all species

Grey Whale, Eschrichtius gibbosus

Blue Whale, Balaenoptera musculus

Finback Whale, Balaenoptera physalus

Sei Whale, Megaptera nouacangliae

Sperm Whale, Physetercatodon

Southern Bald Eagle, Haliaeetus leucoce_phalus leucocephalus

American Peregrine Falcon, Falco peregrinus auatum

El Segundo Blue (butterfly), Shijimide-oides battoides allyui

In addition, the U.S. Fish and Wildlife Service has proposed that seven
terrestrial species native to San Clemente Island, sometimes compared to the
Galapagos, be added to the endangered species list. 12/ More recently, several
endemic snails have also been proposed for protection, the most important being
the California brackish water snail, Tryonia imitator, found largely in coastal
lagoons in southern California.

K E L P B E D S A N D T H E I R A S S 0 C I A T E D F L 0 R A A N D
F A U N A

The kelp beds of southern California are named for the dominant algal

312

species, Macrocystis pyrifera, which often grows in dense forest-like stands
along the coast in waters from 20 to 80 feet deep. 13/ Though some controversy
still exists, it is generally accepted that kelp pl@_nts are not damaged by
oiling. However, kelp provides an important subtidal marine habitat for a rich
and diverse flora and fauna which may be adversely affected by oil trapped and
held in the fronds or emulsified and spread to submerged animals on the
bottom. ]J4 The EIS for OCS Lease Sale #35 summed up the importance of kelp
beds as habitat in the following manner:

We feel kelp beds are such an important marine habitat to southern
California that a generalized overview section should be included.
Associated with kelp beds in southern California and-no.rthern Baja
California are over 810 kinds of organisms. This species count was
taken from North (1971) who listed 57 species of fishes, and Bright
who listed over 625 invertebrate species (74 common) associated with
kelp beds. The majority of these species.may not have an obligatory
relationship with giant kelps, but they utilize every conceivable
nook and crevice of the plant and adjacent area thereby greatly
increasing the total habitat available to them. 15/

Also, fish and invertebrates use kelp and other marine alqae for shelter,
food, and a place to lay their eggs. 16/ Therefore, the beds,are vitally impor-
tant to the marine sportfishing indusf-ry (party boat) since many sport fish are
found in association with kelp beds. 17/

Kelp Is also a commercial resource in its own right; it has been harvested
and processed in California since 1910. As can be seen from the list below,
kelp is an important b 'iological and economic resource, according to values esti-
mated for two of the state's 74 commercial beds. Values can be considered to be
conservative-as they are based on 1950-196.0 dollars.

-Resource Value, dollars

Commercial Fish, 130,000
Sport Fish 90,000
Lobster 50,000
Abalone 10,000
Kelp 500,000

Total 780,000

(Value of marine resources from the vicinity of t he Pt. Loma and La
Jolla kelp beds (squares 842 and 860) for 1955-56, except for kelp
where a yield of 25,000 tons was assumed and is considered to be
about average for plentiful years, based on data from theDepartment
of Fish-and Game..) 18/

Kelp beds are scattered rather irregularly along the mainland coast.
California beds have decreased-in size since the early 1900s when they covered-,
approximately 100 square miles. Today they cover less than 75 square miles. 19/
The decline was espec-ially severe in southern California where some of the ma@jor
beds have all but disappeared from temperature changes,.sewage discharges, and
kelp grazers. 201

The kelp beds extending from Po int Conception to the Santa Barbara city

313

limits are very dense and contribute a large percentage to the commerci al harvest.
Kelp forests are also scattered in relatively dense stands from southern Ventura
County to northern Los Angeles County, in western Santa Monica Bay, and along the
Orange County coastline. San Diego County has very large beds intermittently
from Carlsbad to Point Loma. The offshore islands all have kelp beds surrounding
them, their size and extent varying according to season, substrata, etc. Santa
Barbara Island has especially dense and extensive beds surrounding it. Leases
sold in OCS Sale #35 and those that may be sold in Lease Sale #48 are a serious
potential threat to these heavily fished beds. The commercially important Point
Conception beds are similarly threatened by development of the Santa Ynez Unit in
the western Santa Barbara Channel. The scattered beds off the Orange County
coast would be affected by a spill emanating from the San Pedro Bay leases and in
the more distant future, the exceptionally large beds off the Point Loma peninsula
and La Jolla could be affected by oil spilled from tracts selected for EIS con-
sideration in OCS Lease Sale #48. Finally, all kelp beds surrounding the four
northern Channel Islands are threatened by existing and future petroleum activity
in the Channel.

The actual size and configuration of the kelp beds varies yearly and season-
ally, so precise mapping of the beds is not possible. Two of the most current
sources were used, however, to give the approximate location and size of the
major kelp stands. Esca-Tech's Aerial Reconnaissance in Support of the Bureau
of Land Management's Southern California Baseline Studies and Analyses provided
t@e -most precise survey to date. The incomplete draft of Prominent Southern
California Marine Resources being developed by the California Department of Fish
and Game was also used for comparative purposes. Unfortunately, only the first
and second surveys of Esca-Tech's aerial reconnaissance, which were conducted
less than one month apart (during October), are available and hence do not repre-
sent a full seasonal range of kelp distribution. The contractors for that survey
found an increase in bed size on the sheltered side of the islands during the
winter months, a fact not represented on the sensitive resource maps. 21/ In
addition, the capabilities of the infra-red film limited penetration to a depth
of 1 cm., while use of USGS 1:24,000 base maps precluded representation of any
kelp strands less than 100 feet wide. Subsequently, Esca-Tech's 1:24,000 kelp-
bed maps were reproduced on 11" x 17" sheets at.varying scales which ranged on
the southern coast from approximately 1:47,000 to 1:62,500 and for the islands at
approximately 1:30,000. From these small-scale maps, the kelp beds were trans-
ferred to our USGS 1:24,000 base maps. The location, size, and extent
of kelp beds were then interpolated: for these several reasons, the beds are thus
presented in a generalized form. To the extent that they are inaccurate, the
error is one of under-representation.

R 0 C K Y I N T E R T I D A L

Tide pools and their unique inhabitants are one of the most heavily exploited
of California's marine resources. In the southern part of the state, recreation-
al, scientific, and educational pressures are especially intensive, as rocky inter-
tidal areas exist only in widely spaced stretches along the coast. However, the
intertidal zone is most important for its ecological role. Many marine species
depend on tide pools during some part of their life cycles, either for spawning,
or during the juvenile or latter stages of their lives. 22/ The Southern
California Bight supports an especially diverse variety of intertidal organisms,
as it is a transitional area with a great number of 10 endemics (organisms with
a North-South range of 60 miles) in addition to the many better-known tide pool
plants and animals. 23/

314

Because of the distance between intertidal areas on the mainland, repopula-
tion in the event of a large spill could take years, as recruitment in these
areas must normally come from within. The islands, on the other hand, have
80% rocky shoreline, but are too distant from the mainland to represent a
sure source of recruitment. The EIS for OCS Lease Sale #35 summed it up this
way:

The damage from a large case I oil spill could be severe to the rocky
shore interti.dal. Smothering should cause th *e principal damage to spe-
cific upper intertidal species of plants and animals where all indivi-
duals oiled will die. The toxic effect from crude oil reaching shore
in three or four hours is unknown, but will not be as severe as is caused
by refined oil spills. Although the entire intertidal community will not
be killed, many individuals of a variety of species will be. Reproduction
and repopulation will be retarded for several months, and the extinction
of rare endemics is a possibility. Biological recovery will take,up to
five years. However, the time required for the decimated intertidal
community to return to ore-spill conditions is unknown.

Cleanup operations of intertidal areas could cause total destruction of
the rocky shore communities and significantly harm the communities of the
sandy beach areas actually cleaned. 24/

Because of the damage to rocky intertidal areas that could result from both
accidentially released petroleum and subsequent cleanup operations, adequate
spill response capability should be available to prevent oil from reaching tide-
pools on the mainland shore in the event of a major spill.

Each of the five southern counties has rocky intertidal areas which could
be given priority for protection. As can be seen from the maps, Santa Barbara
and Los Angeles counties have the greatest percentage of shoreline characterized
as ."rocky" by the U.S. Corps,of Engineers. Rocky intertidal areas comprise
24 percent or 26 miles of the shore of both counties. About 11 miles, or 15
percent of the San Diego shoreline is rocky, while Orange and Ventura counties
have only three miles of rocky shoreline each. 25/ Two relatively undisturbed
rocky intertidal areas on the Santa Barbara County mainland are considered by
Dr. Adrian Wenner, a marine biologist at the University of California, Santa
Barbara, to be critical for repopulation in the event of a large channel oil
spill. 26/ Wenner has proposed that Point Conception and Naples, along with the
west end-of Santa Cruz Island, be given reserve status by the.state because of
their strategic location in terms of channel currents.

0 F F S H 0 R E B A N K S

The Southern California Bight represents an atypical continental margin with
a highly varied topography quite different from the more characteristic contin-
ental shelf-and-slope configuration. Bordering deep basins are numerous rocky
outcrops forming ridges which are shallow enough to support very complex associa-
tions of plants and animals. Some of these areas, such as Osborne Bank, Tanner
Bank, Cortes Bank, Thirty@Mile Bank, Forty-Mile Bank, and shallow bank areas in
the Santa Rosa-Cortes Ridge were first identified by fishermen.

While the regional significance of the offshore banks to commercial fishing
interests is well known, the significance of these areas as habitat for unique
marine floral and faunal species, such as the purple coral, is just beginning to

315

be'understbo'd. Information about the offshore banks is inadequate to date, but
as new data appear the ecological value of these shallow areas continues to be
reaffirmed.

The marine mammal/bird portion of the-BLM baseline studies program identified
several of the banks as areas of great importance to seabirds. Most prominent
among those was the northern half of the Santa Rosa-Cortes Ridge, as well as
Osborne Bank, Forty-Mile Bank, the San Clemente Escarpment, and Lasuen Knoll. The
Santa Rosa-Cortes Ridge was shown to harbor a tremendous concentration of cetaceans
(whales, dolphins) and pinnipeds as well, during the month of July. 271

To date, there is no published information on the banks off southern Cali-
fornia, but from conversations with the principal investigators for BLM's subtidal
baseline research on Tanner and Cortes Banks, and from several unpublished sources,
these heretofore "unknown" areas have been described as follows: "The Tanner-Cortes
Bank region is an extremely high energy environment characterized by rocky ridges
and pinnacles rising-from the sea floor to within three feet of the surface - in
some cases." 28/ These are shallow water areas in a deep ocean setting, as far as
T20 miles offs-hore. In addition to the spectacular relief, all researchers have
noted extremely clear water, apparently so because muddy runoff from land seldom
reaches this far out. As a result of the clear water and concomitant high light
levels, as well as the presence of the California current which bathes the banks in
nutrients and planktonic organisms, productivity and diversity of plant life appear
to be exceptionally high. Dense stands of brown algae cover the banks to a depth
of 100 feet. Below this canopy, where light levels are reduced by shading, dozens
of varieties of red and brown algae proliferate. These include a number of forms
normally found intertidally, or in shallow nearshore waters, or in areas distant
from southern California. These algae thrive together on Cortes Bank in a very
uncommon mixture of species. The depth of the photic zone on these outer banks is
not precisely known; however, algae have been observed as deep as 200 feet.

The fauna of Tanner and Cortes Banks seem to be highly unusual by virtue of
the juxtaposition of the flora and fauna of shallow rocky substrates and the deep-
water, open-ocean community of the California current. Dense schools of pelagic
fish are found together with unusually abundant benthic, near-shore fish. All
researchers surveyed stated that there were more fish seen on the banks per dive
than seen anywhere else in the Southern California Bight. The three most common
species sighted were sheephead Pimelometopon pulchrum, blue rockfish Sebastes
mystinus and ocean white fish Caulolatilus princeps. Sheephead are m-uch sought
af-t-erby skin divers. Blue rockfish -- the most important sport fish in northern
.California and very important in southern California as well -- are also fished
commercially. Ocean white fish are not heavily fished but are regarded as. excel-
lent sport fish. Quast conducted a series of belt transects in five areas of Baja
California and southern California and found the greatest densities in Papalote
Bay, Mexico, where a mean of 26 sheephead per acre were counted. 29/ Smith's
estimate for Tanner Bank was 177 sheephead per acre. Although the-methods used
were differen't. with Quast's evidently yielding lower results, the large
numbers of fish found on Tanner Bank remains quite significant. Packs of sea
lions are often observed feeding among these dense schools.

The invertebrate communities on the banks also have been described as being
very unusual and quite striking. The invertebrate fauna include, for example:
previously undescribed species of nudibranches; huge aggregations of sea anemones.
and solitary corals; sea stars and urchins; gorgonian octocorals; both red and

316

purple forms of the rare, fragile hydrocoral Allppora; large numbers of the cowrie
Cypraea spadicea (a shell-collector's item); 5-n-d, sufficient abalones and lobsters
to be of commercial value. Thus, the areas of Cortes Bank and Tanner Bank lying
within the photic zone appear to represent an.extremely uncommon environment
compared to other locations in the Southern California Bight.

Although quantitative data from these subtidal investigations have not yet
been analyzed, preliminary assessment of data gathered to date has yielded tenta-
tive identification of 94 new species and confirmed the presence of the purple
coral in dense colonies on Tanner and Cortes banks. 30/. It was reports of the
presence of hydrocorals on the outer banks that firsf-prompted BLM to initiate
preliminary surveys of the area, then to fund a separate subtidal baseline investi-
gation of Tanner and Cortes banks. As a result of these early surveys, Stipulation
6 of OCS Lease Sale #35 was promulgated. Stipulation 6 requires distant dumping
of drilling muds and cuttings in order to protect the biological resources of
Tanner and Cortes banks.-

Protection of coral communities is essential because of the slow growth'
of the species. It grows only between one-half and one centimeter per year
(personal conversation with Dr. Gay Asterello 5-10-77). Protection was gained for
purple coral found in California waters by state establishment of the Farnsworth
Bank Ecological Preserve southwest of Santa Catalina Island. This bank is similar
to Tanner and Cortes banks in federal waters but much smaller (only 200 by 575
yards). It contains the purple phase of Allopora, which is rare in California,
but the red phase is even more scarce and has never been reported'in southern
California except at Cortes and Tanner banks. Of 244 colonies of Allopora counted
on Tanner Bank, 242 were red. 31/

Though the other banks in the Southern California Bight are even less studied
than Tanner and Cortes, it has been reported that purple coral is also found on
Osborne Bank, five miles south of Santa Barbara Island. The Osborne Bank area is
also one of the most productive grounds for both sport and commercial fishertes. 32/
Three tracts west of the Santa Barbara Island were sold in Lease Sale #35, and
three more are being studied in the EIS for Lease Sale #48 just northwest of Osborne
Bank. Sale of these leases, and development of those sold in Sale #35, would
threaten Osborne Bank in the event of a spill. Lasuen Bank, between Santa Catalina
Island and the Orange County coastline, is also a heavily fished area, and tracts
just north of this bank were sold in Lease Sale #35. Tanner and Cortes Banks, the
shallowest and best studied of the offshore banks in federal waters, are the most
threatened by petroleum development activity. Exploration is currently taking
place on both.

Although exact deliniation of the coral communities on Tanner and Cortes banks
has not yet been made, Secretarial Order 2978, "Outer Reefs'i states that "...These
reefs are unique formations and their associated marine life is of great scientific
interest and value to students of the sea and it is in the public interest to,pro-
tect these formations of great scientific and aesthetic importance for the benefit
and enjoyment of the people. There is an immediate threat to these coral reefs
resulting from their being subject to commercial exploitation that places them in
danger of being destroyed...." 33/

In order to protect the unusual and highly productive shallow areas of the
offshore banks within the photic zone, USGS should not approve any permit for the
location of a structure within or above the 70-meter depth contour of the Osborne

317

Bank, Tanner Bank, Cortes Bank, or Santa Rosa-Cortes North Ridge until studies
on the effects of oil and gas operations on the biological productivity of the
offshore banks are completed and specific protection strategies are devised for
those resources. Furthermore, because the red and purple forms of Allopora coral
found on the offshore banks are so unusual and slow to recover from any damage,
the Interior Departmen-t should survey the-locations of these coral communities on
all. offshore banks and not permit any structure to be placed in these locations-.

C 0 A S T A L W E T L A N D S

Many studies have underscored the need to protect and maintain the waters,
tideflats, and marshes of California's estuarine areas -- those areas collectively
referred to as coastal wetlands (Bauer and Speth, 1974). Wetlands and estuaries
provide a number of services in the public good as functioning ecosystems: flood
control, data source for scientific investigations, pollution abatement, spawning
grounds for both sport and commercial fish, and feeding and breeding grounds for
many species of waterfowl, shore, and marshbirds. 34/

Coastal wetlands have been greatly diminished following the great influx of
population to the southern California area during and following World War II.
Hendrickson estimates that there were once 26,000 acres of productive wetland
habitat in southern California. 35/ Estimates of wetland acreage lost to urbani-
zation statewide range from 60 to70%, and for southern California alone
from 75 to 90%. 36/ Despite the differences in these estimates, all
sources are in agreement with regard to the value of these remaining wetland
areas. The 8,500 acres of marsh and mud flats remaining in southern California
provide essential habitat for hundreds of fish and wildlife species, including
several rare and endangered birds which are almost totally dependent upon coastal
wetlands. The remaining California wetlands are, therefore, increasingly valuable
and increasingly critical to ecological balance. Recognizing this, the policy for
estuaries and wetlands in the California Coastal Plan states that "...all remaining
coastal estuaries and wetlands and buffer areas necessary to protect wetlands and
their wildlife and bird habitat values shall be preserved, enhanced, and where
possible, restored." 37/

Regarding the sensitivity of these valuable areas to oil spill, the U.S.
Fish and Wildlife Service has stated that:

If oil from a large spill wer e to enter an estuary, extremely adverse
biological impacts could result, including elimination of several
endangered bird species (clapper rail and California least tern) and
certain temporary and permanent floral and faunal species from the
oiled estuary. Further destruction of estuaries in southern affiliated
species (sic) will be eliminated from the coast because of nursery
ground and habitat destruction. 38/

Protection of wetlands from spilled oil should receive highest priority
because of:

1. the disturbance to nesting and feeding areas necessitated by cleanup opera-
tions (particularly during breeding and migration seasons);
2. the vulnerability of shorebirds and waterfowl to coating by oil and sub-
sequent death from chilling and ingestion of hydrocarbon compounds;
3. the nature of the dense vegetation surrounding the open water areas of a
marsh, which would tend to entrap oil and prevent removal; and,

318

4. the tendency of sediments.in a shallow, tidally influenced area to
trap hydrocarbons and release themslowly thereafter. 39/

Since-most oil cleanup methods would in.themselves damage wetlands habitats,
the preferred course of action is to prevent oil from getting into these areas. 40/

Most wetlands open to the sea by way of relatively narrow channels. Thus, oil
containment booms could be designed or adapted to fit these channels and could,
perhaps, be stored nearby for rapid deployment.

Wetland areas considered 'most vulnerable to spills from OCS activity are those
with unrestricted openings to'the ocean as well as close proximity to lease areas
and/or shipping lanes. In Santa Barbara County,the Santa Ynez River, Goleta Slough,
and El Estero (Carpinteria Marsh) are important wetlands of this type, supporting
150 local species of water-associated birds, plus providing stopping points for
thousands of birds in the Pacific Flyway.

Significant numbers of shorebirds, waterfowl, and a variety of other water-
associated birds are dependent on these Santa Barbara coastal wetlands for survival.
The County possesses a scant 900 acres of such wetlands, 80% of them located at
Goleta Slough, Carpinteria Marsh, and on the Santa Ynez River. @Ll/

The Santa Clara River estuary, Mugu Lagoon, and the Ventura River mouth com-
prise the vulnerable wetlands of Ventura County -- some -2,290 acres of marsh and
mud flat habitats. Mugu Lagoon itself contains 95% of the county's wetlands. It
is estimated that'in excess of 200 species use the marsh and mud flats of Mugu
Lagoon and other wetlands of the county. The light-footed clapper rail, a species
now in danger of extinction, is found at Mugu Lagoon, one of the few remaining areas
in-Californ.ia supporting clapper rails. 42/

Mugu Lagoon is considered by Hendrickson to be the largest and most pristine
coastal wetland habitat in southern California. 43/ The other Ventura County
wetlands, though only 5% of the total, are extr6m-ely important because of the
generally ari'd nature of the adjacent area. In Los Angeles-County, all that re-
mains of the large wetland marshes and mud flats that once covered the coastal
area of that county,are-Ballona Creek, a 350-acre degraded wetland, and Colorado
Lagoon. About 96% of the county's marshes and mud flats have been lost to -
dredging, filling, and other developments, destroying the value of these habitats
for wildlife. The primary value of the remaining marsh acreage is that it provides
wildlife a small oasis of natural habitat at the edge of a metropolitan desert.

Orange County has two important wetlands potentially threatened by OCS develop-
ment. The salt marshes, mud flats, and protected waters of Anaheim Bay, Bolsa
bay, and Upper Newport Bay are critical to the maintenance of shorebird and water-
fowl populations in the county, the state, and the Pacific Flyway. These three
bays contain almost all of the remaining wetland acreage in the county. 43a/
Fortunately, upper Newport Bay is not threatened and will not be discussed here.
Bolsa Bay and the approximately 1,500 acres of degraded wetland known as Bolsa
Chica is not threatened unless the Department of Fish and Game makes its proposed
Channel cut to restore tidal action to the marsh -- an action that would improve
the quality of the wetlands but would also render them.vulnerable to oil spill.

319

Over,100 species of birds utilize Anaheim Bay, including 23 known resident
species. Breeding colonies of light-footed clapper rails are found in the Bay
and the adjoining Seal Beach National Wildlife Refuge. Other endangered species
found in this estuarine complex are the Cal.ifornia brown pelican, the American
peregrine falcon, and the least tern. 44/

The Department of Fish and Game has estimated that the Anaheim-Bolsa-Sunset
Bay Complex annually supports 720,000 migratory waterfowl use-days, 126,000 resi-
dent waterfowl use-days, and 540,000 migratory species (other than waterfowl)
use-days.

Vulnerable coastal wetlands in San Diego County include, in order of vulner-
ability: Tijuana River Estuary, Santa Margarita River, Aqua Hedionda Lagoon, San
Elijo Lagoon, Los Penasquitos Lagoon, and Batiquitos Lagoon. The latter three
lagoons and the Santa Margarita Ri-ver are open to tidal action only during certain
times of the year, however. Buena Vista Lagoon and San Diequito Lagoon are both
restricted from tidal action by flood gates, making it unlikely that oil could
enter either wetland.

Of the above areas, the 400-acre Tijuana Estuary remains the least disturbed
and thus the most important wildlife habitat, but it is also potentially threatened.
Twenty tracts directly off the San Diego coast will be included in the Bureau
of Land Management's EIS for OCS Lease Sale #48. A group of ten tracts lies
directly off San Diego Bay and just above the Tijuana Estuary. The extensive wet-
lands in lower San Diego Bay would probably not be reached by a spill because of
the configuration of the Bay, but the Tijuana Estuary is definitely threatened if
development of those leased tracts proceeds.

All other wetland areas in San Diego County have been altered or degraded to
some extent by human encroachment but still remain essential as wildlife habitats.
The *size of these wetlands ranges from 250 to 600 acres of well-developed salt
marsh communities and open water area. A very thorough description of each can
be found in th'e San Diego Coast Regional Commission's report entitled "Life in the
Sea."

S E A B I R D R 0 0 K E R I E S

The Channel Islands and surrounding waters provide essential feeding, nesting,
and breeding areas for resident and migrant seabirds in the Southern California
Bight. These pelagic (open ocean) birds are the most conspicuous and numerous
avian group found in the OCS lease areas. 45/ They comprise such large species as
shearwaters, petrels, murrelets, auklets, i-nd gulls. Some of these birds spend
most of their lives on or above the open ocean, coming ashore only in selected
areas to breed and nest.

These migratory species, as classified under the conditions of bilateral
treaties with Canada, Mexico, and Japan (pending), are protected under provisions
of the Migratory Bird Treaty Act. Other birds are additionally protected by the
Bald Eagle Act of 1940, the Endangered Species Conservation Act of 1969, and the
Endangered Species Act of 1973. The U.S. Fish and Wildlife Service is responsible
for enforcing 'these acts, establishing and maintainIng a system of refuges, and
implementing management programs.

In order to resolve resource conflicts that could occur as a result of

320

development of leases sold in OCS Sale #35, the U.S. Fish and Wildlife Service
recommended several preliminary strategies to protect seabirds:

No oil exploration, development, or production facilities be placed upon
the offshore rocks of the proposed lease sale area; no oil exploration,
development, or production activities be conducted on or within the
vicinity of Anacapa..Island or important pinniped and seabird breeding
areas on San Miguel and if it is determined that brown pelicans feed in
.extensive numbers in the vicinity of OCS Lease Sale Area Santa Rosa-
Cortes South, that oil operations be restricted to minimize the
possibility of an oil spill affecting the species. 46/

These recommendations were made in view of the fact that oil spills
are known to be a tremendous hazard to marine-associated birds. The vulner-
ability of most aquatic birds to oiling and subsequent death is well documented
in the literature. 47/ In its analysis of the effect of oil on aquatic
birds, the Santa Barbara Channel EIS concluded that in the event of a major oil
spill in the Santa Barbara Channel, the most visible damage to marine ecosystems
is the damage to populations of marine birds present on the waters of the Channel
at the time of a given pollution incident.. 48/ The EIS for OCS Lease Sale #35
quoted Erickson (1963) who noted that oil pollution may serve as an agent of inter-
mittent but conti,nuing attrition, especially on-those migrant birds using,coastal -
and offshore waters.

Norris further concluded that i.t is reasonable to expect that
the foraging of most, if not all, of the seabi'rds breeding in 'the Channel Islands
would be adversely affected by oil spilled on the sea surface. 49/ During the
breeding season,' birds.are restricted in the area over which they may forage by
their commitment to a fixed nesting site. During this same period, food require-
.ments are at a maximum, as the adults need to forage not only for their own needs,.
but also@in order to gain energy for egg production or for feeding growing young.

Foraging generally takes place close to the breeding colonies
indicated on the inventory maps. Areas observed to support high densities of,
feeding birds (in addition to those areas immediately adjacent to breeding colonies)
'were: over the crown and-sides of the northern Santa Rosa-Cortes Ridge; the Santa
Barbara Channel; Osborne Bank; Forty-Mile Bank; the San Clemente-Escarpment; and,
in late spring, inshore areas such as Lasuen Knoll. 50/ As can be seen from the
maps, all seabird rookeries are now found on the Channel Islands, though histori-
cally most species once bred and nested on the mainland.as well.

'From their experience with large oil spills, the U.S. Fish-and Wildlife
Service has concluded.that some birds are more vulnerable to damage by.oil pollu-
tion than others. The following factors determine the vulnerability of avian
species:

1. diving and pursuit seabirds are highly susceptible to oil pollution
because they spend much time in the water;
2. among diving birds, those who roost on the water at night are more
vulnerable to,oiling-because of increased.exposure and the
increased chance of coming on a slick,-unawares in the night;
3. the number of individuals of a given species affected by an,oil spill
is determined by their total number and distribution as.well as by

321

the extent of the spill. For example, a flocking species found in large
numbers in inshore areas where there is less chance o, 'f avoiding an oil
slick (e.g., surf scooters and Western grebes) is more likely to suffer
heavy mortality in the event of a spill than a solitary species that
roosts on land;
4. diving species that become flightless during molt or that do not fly
because of social bonds with flightless young (common murre, Xantu's
murrelet) and that spend most. of their time in the water are particularly
vulnerable; and,
5. young birds are not thermoregulated (i.e., still retain their down, or
have feathers not yet protectively coated) and are more susceptible
to lower concentrations of oil than adults. 51/

The Fish and Wildlife Service analysis of birds meeting the above criteria of
vulnerability indicated, on the basis of feeding and nesting behavior, that these
particularly susceptible birds are distributed throughout the lease area in as yet
undetermined numbers. The marine mammal/bird baseline studies being conducted
under the auspices-of the Bureau of Land Management will attempt to quantify the
seabirds of the Bight by species composition, habitat requirements, sensitivity to
oil pollution, etc. Though the final results of the first year's research have
not been published, a six-month progress report revealed more information on the
subject than-has been published to date. The progress report characterized the
state of aquatic bird populations this way:

Finally, the avifauna is complex; perhaps 150 species occur more or
less abundantly in the Southern California Bight...(but) for many
nesting seabirds of the Channel Islands, the present populations are
remnants of once much larger populations. The health of the present
populations in many cases is not good; disturbance, chemical pollution,
predators, and perhaps other factors are resulting in reproductive
failure. The future of these populations appears to be in jeopardy,
and they should be protected from future insult if they are to main-
tain viable populations in southern Californ-ia. @_21

In view of the sensitivity of many seabirds to oil spills and their vulner-
ability as a result of Lease Sales #35 and #48, the protection of Channel Island
breeding areas and the surrounding waters which provide foraging areas is essen-
tial to the survival of these species.

As can be seen from Figure.1, according to the California Department
of Fish and Game, all of the eight offshore islands in southern California are
major seabird rookeries. 53/ The list below, compiled from several sources,
shows which bird species E-reed on each of the Channel Islands. �J4

Island Breeding Species

San Miguel Ashby storm petrel, double-crested cormorant,
(Prince Island, Brandt's cormorant, pelagic cormorant,
Castle Rock western gull, pigeon guillemot, Xantu's mur-
Richardson Rock) relet, Cassin's auklet, black oyster catcher,
snowy plover

Santa Rosa Brandt's cormorant, pigeon guillimot, pelagic
cormorant, black oyster catcher, snowy plover

322

FIGURE 1:
SEABIRD ROOKERIES, AND ROOSTING SITES

SANTA BARBARA COUNTY
% \x
VENTURA COUNTY \%

LOS ANGELES COUNTY

SAN MIGUEL I
4 NACAPA ISLAND ri
G R
S@@ SANTA CRUZ ISLAND R
SANTA ROSA ISLAND

R
ORANGE COUNTY

R
SANTA BARBARA I LINA ISLAND R - - - - - - --
G R

SAN NICHOLAS I
SAN DIEGO
a COUNTY
G: MAJOR ROOKERIES %SA CLEM ENTE ISLAND
G R
R: ROOSTING SITES

0 10 20 30 40 50 R

SCALE IN MILES

Island Breeding Species

Santa Cruz Ashby storm petrel, brown pelican, pelagic
(Gull.Island, cormorant, western gull, pigeon guillimot,
Scorpion Rock) Cassin's auklet, black oyster catcher, Brandt's
cormorant, double-crested cormorant, Xantu's
murrelet, snowy plover

Anacapa brown pelican, double-crested cormorant,
western gull, black oyster catcher, pelagic
cormorant

Santa Barbara Ashby storm petrel, double-crested cormorant,
(Sutil Islet Brandt's cormorant,. western gull, pigeon guil-
and Shag Rock) limot, Xantu's murrelet, black-oyster catcher,
double-cres.ted cormorant, Cassin's auklet,
black storm petrel

San Nicholas Brandt's cormorant, western gull, snowy plover
(Begg Rock)

Santa Catalina western gull, double-crested cormorant, Brandt's
(Bird Rock) cormorant, black oyster catcher

San Cl6ente western gull, pelagic cormorant, Brandt's cor-
(Castle Rock and morant, black oyster catcher
N.W. Harbor Islet)

Numerous other sea and shore-associated avian species use-the islands and
surrounding waters as feeding-and.resti,ng sites. These include loons and grebes,
shearwaters,,herons, ducks and geese, rails, plovers, sandpipers, phalaropes,
jaegers, auks, and.many species of gulls and terns.

ECONOMIC AND! RECREATIONAL RESOURCES

In responding to the Bureau of Land Management's resource report requests for
the Lease Sale #48 area, the Director of the Department of the Interior's Bureau
of Outdoor Recreation (BOR) characterized the southern California coastal and off-
shore area as "one of the best known and most heavily used recreation and resort
-destinations in the Un-ited States.", According to,BOR, "The.seasonally warm-water
beaches of southern California-are,intensively-used by the 13 million plus resi-
dents of southern California and 8.5 million visitors@to the region." In pointing
out that the entire southern-California coastal and offshore'area is a recreational
resource.of "special significance," BOR emphasized that the "special significance
intensifies around the Channel Islands, inshore waters, shoreline, estuaries, and
accessible stretches of coast in the vicinity of population centers and resort
destinations." 55/

The southern California lifestyle is strongly associated-with the region's
marine and coastal environment. Marine recreation is a multi-million dollar
industry and any degradation of recreational resources caused by an-oil spill
could result in substantial economi.c Tosses. Of those, the major

1324

categories of resources vulnerable to damage are beaches, recreational fishing
areas and their associated harbors and marinas, commercial shellfishing areas,
and diving spots.

B E A C H E S

One of the most heavily used of southern California's recreational resources
is its expansive beaches. Over 12 million people visited the major state beaches
'in southern California last year.

Recreational use of southern California's beaches returns millions of dollars
in revenue yearly. Tourism, and recreational enjoyment in general, are dependent
upon the quality of the experience provided. In addition to heavy human use, which
occurs primarily during th 'e summer months, beaches are used during the winter as
feeding areas for migrating shorebirds and waterfowl. 56/

In.the Ventura County Coas,tal Study of 1974, the County Parks Commissions
noted:

The singularly most unique recreational feature of Ventura County
is its long Pacific shoreline. Few coastal counties in California
have more miles of beaches suitable for boating facilities, day
and overnight camping, fishing, clamming, surfing, and general
play use. Without doubt, the Ventura coastline is the County's
outstanding recreational resource.

'The southern five counties are noted for their expansive beaches, almost all
of which are suitable for swimming.

A total of 83.5 miles (76%) of Santa Barbara County's shoreline is classed
as sandy beach, of which about 67% yet, for the most part, is privately owned and
remains undeveloped. The 14 miles of federally-owned sandy beach is mostly within
the boundary of Vand enberg Air Force Base. The 9.5 miles of state and county-
owned beaches receive nearly 750,000 visitors annually. Such heavy use precludes
nesting activities on the beach; however, during the off-season for bathers and
during early morning and late evening hours of the summer the beaches are visited
by shorebirds. 57/ With the exception of the shoreline north of Point Conception,
all Santa Barbara County beaches are vulnerable to oiling from current-and future
petroleum development in both state and federal waters.

About 38 miles (93%) of the Ventura County shoreline is classed as sandy
beach, of-which 28 miles (74%) is in public ownership. For the season of 1968-1969,
the Department of Parks an 'd Recreation estimated that its beaches in Ventura County
accommodated over one million visitors. This use occurs primarily during the
summer months. However, during the winter migration of shorebirds and water fowl,
the beaches provide feeding areas for long-billed plover, whimbrel, sanderling,
western sandpiper, and the least sandpiper. 58/

Development plans have been submitted to USGS for the Hueneme and Santa Clara
units in federal waters just off the western Ventura County coast. Actual
development, however, will probably not begin until early 1980. The eastern
Ventura County coast currently is not threatened by any offshore activity.

325

About 51 miles (77%) of the Los Angeles County shoreline is classed
as sandy beach. City, county, and state beaches in Los Angeles are among the most
heavily used in the state, particularly during the summer months. However, during
the off season the beaches are used by migrating shorebirds as nestinq sites.
Federal OCS development does not directly threaten the Los Angeles coastline,
since tracts in Santa Monica Bay were deleted from Lease Sale #35. Increased
marine traffic, however, could pose an indirect threat if Santa Barbara Channel
OCS production is transported by tanker.

Orange County has 38 miles of sandy beaches, comprising approximately 92%
of its coastline. Nearly 23 miles of the beach areas are in public owner-
ship and thus support intensive recreational use. The habitat is also available
for bird nesting and feeding during evening and morning hours. 58a/ Plat-
forms In state tidelands and grant lands have been producing off-Long Beach, Seal
Beach, and Huntington Beach without major mishap for the'last 20 years. Thirteen
federal leases were sold off the Orange County coast in OCS Lease Sale #35. Shell
Oil Company has a certified discovery, and is in the process of exploring develop-
ment options with state and federal agencies. Development drilling could begin
as early as 1978. An additional 27 tracts along the county's coast are being
studied for possible leasing in OCS Lease Sale #48.

About 65 miles (85%) of the San Diego County shoreline is classed as
sandy beach. Over half (41 miles) of the beaches are in public ownership and
heavy recreational use occurs during the summer time, except on federally-owned
lands such as Camp Pendleton. Federal lands with limited access priviledges have
provided essential refuge for at least 75 of the 471 pairs of least terns that
depend on county beaches for nesting sites.

Development of existing leases in southern San Pedro Bay poses a possible
oil spill risk to northern San Diego County beaches. The greatest potential
threat to@the county's coastline would be the sale of the 20 tracts chosen for
future study in the EIS for OCS Sale #48. They extend along the entire coastline,
approximately 5 to 12 miles offshore. Because of-their great length, beaches are
impossible to protect entirely from spilled oil. In the event of a spill, main-
land beaches are relatively easy, but still expensive, to clean. Losses could
be significant in the case of &spill of long duration such as the Santa Barbara
blowout. Damage to shorebirds and waterfowl nesting and feeding areas could also
be significant during nesting and migrations.

Sandy areas, which comprise only 20% of the islands' shorelines would present
a different-problem in the event of a spill. Beaches on the relatively undisturbed
islands are available for nesting and year-round use by shorebirds and waterfowl.
Pinniped rookeries also tend to be located on sandy areas where large numbers of
animals can congregate during the breeding season. Losses from a spill adjacent
to the islands would be ecological, not economic, and cleanup efforts would
probably only exacerbate the situation. Economic losses could occur, however,
on Santa Catalina Island.

Sandy areas are indicated on the inventory maps at the end of this chapter.

326

S K I N A N D - S C U B A D I V I N G A R E A S

Diving, like many other recreational activities that are coastal dependent,
is a fast-growing sport in California. Using either a snorkel and mask or SCUBA
gear, divers engage in spear fishing, shellfishing, underwater exploration, and
photography.

These Underwater activities are carried out in rocky subtidal and reef areas
where water clarity is greater and marine life abundant. Pressures are great in
some areas, because while there is no shortage of ocean to dive in, there is
a shortage of areas of high scenic and biotic interest and-which are access-
ible and in a near-natural state. 59/

Diving is greatest in the marine life refuges, in areas where
there are extensive kelp beds offshore,'and around the islands, especially the
five northern islands and Santa Catalina. The threat of degradation by an oil
spill is greatest in the western Santa Barbara Channel, adjacent to the Channel
Islands and in the refuges along the Orange County Coast.

Diving areas with high use and desirability are shown on Figure 2. They were
mapped according to information provided in Coastal County Fish and-Wildlife
Resource Utilization by the Department of Fish and Game and the Chart Guide for
Southern.California Boating, Diving and Fishing.

R E C R E A T 1 0 N A L F I S H I N G A N.D S U P P 0 R T H A R B 0 R S

The excellent recreational fishing opportunities available in California
coastal waters have received national attention because of both the abundance of
fish and the variety of species available.

Partyboat, skiff, pier, jetty, surf, rock, and spear fishing are all popular
methods used to catch the many kinds of fin and flatfish available to the south-
ern California angler. Demand for high-yield fishing areas is great. The large
kelp beds, the offshore islands and offshore banks are heavily fished. In 1971,
commercial partyboats for chartering sport fishermen to fishing waters provided
4,600,000 fish for 725,000 anglers. 60/ Onshore, available piers and jettys,
suitable sandy beaches for surfishing, and rocky areas for rockfishing are all
heavily used.
Gruen and Gruen, in a report to the Resources Agencies, characterized sport
fishing as a "...form of recreation that brings considerable external benefits to
California from the expenditures of anglers and from the nature of the experience."
The lists below summarize the findings concerning the economic value of sport
fishing in California and the sport fishing habits in southern California. 61/

Net Economic Value of Marine
Sport Fishing in California 1970

Total Assumed Value
California Per Day Net
Angler Days (Low to High Range) Economic Value

11,910,000 $2 $ 23,820,000
11,910,000 3 35,730,000
11,910,000 4 47,640,000

327

Gaviota an
Santa
Barbara ntena igure
SENSITIVE RESOURC
T -I-
Ventura
Popular Skin and Scu
Port
Huenerne

P, Los Angeles
Santa
C.Uz Monica

Manhattan
f@--ach

LB-ea",,h

Hunt ington
. . . . . . . Beach

pwj
. . . . . . . .. .

-S7

"v,

r
v

4+4
+1.0 151@M KILOWTEM 5m
US
-WIES @Es
N@H @E .460DW -

A,.1 1977

Estimate for 1970 of Marine Sport Fishing
Activity in Southern California
By Type of Fishing

Southern
California
Angler Days

Piers & Jetties 3,730,395
Shoreline 1,467,877
Partyboats 691,092
Private Boats 1,180,924
Other 198,660

Total 7,268, 1948

Source: A Socio-economic Analysis of California's Sport and Commercial
Fishinq Industries, a report to the Resources Agency by Gruen
and Gruen, 1972.

Sport fishing in California produced over $14 million in gross expenditures in
1970 as well as substantial,"secondary" income or employment derived from-
the gross expenditures of consumers. Potential,loss of income to a particular
area-should be.of considerable concern to decisionmakers. On a statewide level,
the secondary income effects of sport fishing ($300-400 million) are larger than
those of commercial fishing ($200-300 million). Popular sport fishing areas in
southern California are shown in Figure 3.

The National Conference on Marine Recreation found that services to recrea-
tional fishermen provided a dominant share of the income to a multitude of coastal
communities. 62/ Much of this revenue.is brought in by turnover support facilities
and services Frovided by various harbors.

Harbor areas of the offshore islands are shown generally in Figure 4, below.
For the mainland, harbors and marinas have also been mapped, but as part of the
"Inventory of Petroleum-Related.Facilities" (Appendix 3) in the back of this
report. Marinas and harbors--both mainland and island locations--are considered
as sensitive resources-for-the purposes of-this chapter because of their vulner-
ability to oil spills. The adverse-effects of an oil spill to marinas and harbors
are related to the following:

1. damage to fishing grounds;
2. destruction of larval stages of commercially valuable species;
3. the high cost,of cleaning oiled vessels; and,
4. harbor closure and resultant loss of fishing time.

Recreational shellfishing is also a very popular activity, with high demand
for suitable areas. Clam beds in cobble and sandy beaches along the coast are
heavily used, and rock crabs support a sizable sport fishery as well. 63/ The
California spiny lobster, rock scallops, and various species of abalone are highly
prized,-but are able to be taken only by skin and"scuba divers.

Marinas and harbors are fairly easily protected from an oil spill through use
of booms; this does not.- however, prevent losses incurred from prevention of boat
use. Recreational fishing grounds, on the other hand, are less easily delineated

329

iota Capitan
Figur
pinleria
t
SENSITIVE RESOUR
Venture
0, Popular Sport F
L LL ftt

LOS AngeleS
D- Santa
'A Monica

Manhattan
Beach

tNA

CD
CT# A-

ty;, f

-1@ KIP

Al
M

1-41

0
15 K

NOWH SCALE
1-1 all O= FC s
L I
I I IT- -1 T1

Gaviota cVftan
Saft Figure
Baftm
HARBOR A
.1 L I N_ ra OFFSHORE I
i. -c-Ulyer 44 4 A:@l I I I I @
i--2. Boachers 3. Chinos p t
Harbo 9 Har r X_
Bay 4. Prisoner,'s Harbor
Ll- @ Lm ArgeW
QW MAW W C Vrenchy's -Cove S"
5. S u glor s Mwca
F A ve =lallw

'luningtw
Z_ Bh

@A --o
7. me a ve
IS IV
8. Isthmus Cove
Cata -na
ROM Aval h or
Harbor
04 1
I r

li. Wfiso'n's Cove--
F, I I i
7-

12. Pyramid Cove
U
T

N A W

I V/7)JI

L-- - - - -
1,0 is K rATP@@
MCMETM
le --,ML-Jm - - - -
No" 3@ DEWH CLPA M WTVM - - - -
r@, 0@ ow_
OU'Ai5iscT

and protected. Heavily recruited areas are scattered all along the mainland
coast, and may correspond to artificial reefs, kelp beds, areas of high produc-
tivity, or nearby urban areas. Because of the importance of many recrea-
tional fishing areas, local governments and harbor districts, in cooperation with
the Department of Navigation and Ocean Development (DNOD) and the Department of
Fish and Game, should assess their vulnerability to recreational and economic
loss as well as to environmental degradation in the event of an oil spill, in.order
to determine whether existing spill-response plans and equipment are sufficient
to protect these vital interests.

Areas of heavy recreational shellfishing and finfishing, as
well as major marinas and harbors, are indicated on the maps by individual
symbols. Their locations were determined from the following sources: Coastal
County Fish and Wildlife Resources and their Utilization, by the California Depart-
ment of Fish and Game; the draft of Prominent Southern California Marine Resources,
also by the California Department of Fish and Game; and, the Chart for Southern
California Boating, Diving, and Fishing.

T H E C 0 M M,E R C I A L S H E L L F I S H E R Y

The animals which make up the shellfish resource of southern California
(except for the squid*) are benthic organisms, which spend their
lives on the bottom, usually in relatively shallow waters. Because they are so
dependent upon this restricted area, and are not highly mobile like fish, they
are most vulnerable to the effects of pollution or habitat disturbances. Though
the entire southern California fishery could be affected by an oil spill through
loss of ability to use boats in the spill area, fin and flat fish are thought
simply to vacate a spill area. The shellfish, however, would be affected directly
by spilled.oil. Figure 5 shows generally the locations of popular shellfishing
areas offshore of southern California.

Though mollusks (clams, oysters, abalone, and scallops) constitute those
organisms properly referred to as "shellfish" the term is commonly used in refer-
ring to both the mollusks and crustaceans. The southern California commercial
shellfish catch is made up of two crustacean species: the rock crab and the
spiny lobster. Several other crustacean species such as the spot prawn and the
ocean shrimp support smaller fisheries and are not reflected in Table I which
shows the value and amount of shellfish landed in each of the five coastal counties.

Abalone and squid are the molluskan species that make up the remainder of
the commercial catch. Because commercial clammers are restricted to the same
bag limits as sportfisherTnen, a viable fishery does not exist for clams. 64/
The fishery for abalone and lobster, the most highly prized species, depenas upon
rocky areas along the mainland coast, the offshore islands, and offshore banks. 65/

The mainland coast of Santa Barbara County supports commercial harvests of
lobster, crab, and abalone. The largest southern California harvests of rock crab
come from the offshore area from Goleta to Santa Barbara Point. 66/ Abalone is
harvested from the rich kelp beds around Point Conception, north to Point Arguello
and east to Rocky Point. Lobsters are taken off Point Conception, Gaviota,
Tajiquas, El Capitan, Coal Oil Point to Santa Barbara Point, Montecito, Carpenteria,
and Punta Gorda. 67/ The Ventura coast, on the other hand, has few extensive kelp

*The shell of the squid, not popularly regarded as a shellfish,.is internalized--a
thin, chitinous (cartilage-like) structure.

332

Gaviota Capitan

Ba',
'-_@nta Figur
rpintena
SENSITIVE RESOUR
ura
Commercial and
Sh ellfishin
Port
Huenerne

Santa Los Angeles
c%z ISLAND Monica

Manhattan
Beach

bach

Huntington
Beach

. . . . . . . . . .

4
GavictaCapt,

_J1
TRN@
0 5
5 @ES
NOMN IM@E OEPrH CUWA IN METEM

-1 T

TABLE 1: COMMERCIAL SHELLFISH LANDINGS IN SOUTHERN CALIFORNIA

SANTA BARBARA COUNTY COMMERCIAL SHELLFISH LANDINGS

SPECIES 1966 1967 1968 1969 1970

ABALONE: lbs. 1,442,336 1,330,278 1,109,032 1,166,239 1,043,683
value $279,013 $263,268 $292,211 $376,183 $356,084
$/lb. .193 .198 .263 .322 .341

ROCK CRAB: lbs. 102,102 77,798 102,623 126,435 135,228
value $6,398 $4,982 $6,588 $11,189 $11,078
$/lb. .063 .064 .064 .088 .082

SPINY LOBSTER: lbs. 95,524 84,916 93,114 75,488 47,599
value $77,460 $69,636 $79,722 $77,880 $58,127
$/lb- .811 .820 .856 1.032 1.221

VENTURA COUNTY COMMERCIAL SHELLFISH LANDINGS

.ABALONE: lbs. 109,466 50,279 112,368 58,060 46,663
value $21,656 $10,162 $28,704 $18,250 $15,658
$/lb. .198 .202 .255 .314 .336

SPINY LOBSTER: lbs. 27,995 26,746 18,525 .20,539 32,946
value $22,701 $21,933 $15,861 $21,190 $40,234
$/lb. .811 .820 .856 1.032 1.220

SQUID: lbs. 1,305,038 2,592,543 2,660,395 3,036,160 4,878,300
value $17,160 $38,696 $37,318 $43,109 $70,561
$/lb. .013 .015 .014 .014 .014

LOS ANGELES COUNTY COMMERCIAL SHELLFISH LANDINGS AND SHIPMENTS

ABALONE: lbs. 1,045,753 772,158 1,525,777 1,276,354 1,014,220
value $186,566 $149,685 $363,479 $414,491 $330,474
$/lb. .178 .194 .238 .325 .326

ROCK CRAB: lbs. 207,536 235,217 234,585 300,077 315,752
value $@5,399 $27,477 $29,777 $37,505 $41,348
$/lb. .122 .117 .127 .125 .131

SPINY LOBSTER: lbs. 160,894 173,689 89,497 104,051 70,381
value $137,886 $151,321 $85,902 $118,110 $82,623
$/lb. .857 .871 .960 1.135 1.174

SQUID: lbs. 6,513,192 5,776,010 7,693,532 6,182,983 11,085,253
value $91,736 $98,937 $117,389 $124,206 $249,584
$/lb. .014 .017 .015 .020 .022

ORANGE COUNTY COMMERCIAL SHELLFISH LANDINGS

ABALONE: lbs. 144,081 35,665 37,763 2,870 1,700
value $26,521 $7,100 $8,835 $935 $586
$/Ib. .184 .199 .234 .326 .345

SPINY LOBSTER: lbs. 39,275 35,319 19,308 23,269 9,241
value $33,659 '$30,770 $18.533 $26,412 $10,848
$/lb. .857 .871 .960 1.135 1.174

SAN DIEGO COUNTY COMMERCIAL SHELLFISH LANDINGS AND SHIPME9TS.

ABALONE: lbs. 638,921 587,419 740,978 514,768 479,093
value $101,915 $108,167 $174,763 $148,527 $133,836
$/lb. .160 .184 .236 .289 .279

SPINY LOBSTER: lbs. 165,400 129,214 91,406 82,897 59,857
value $137,624 $114,273 $92,605 $99,811 $69,925
$/lb. .832 .884 1.013 1.204 1.168
334

Source: California Department of Fish and Game, 1973

beds and does not support significant commercial shellfish harvesting. Some
lobsters are taken just south of Pitas Point and crabs are taken just south of
Point Mugu only. Squid is also taken in that area near the Los Angeles-Ventura
County border.

The most important shellfishing area in Los Angeles County is seaward of the
San Pedro breakwater out to Dago Bank, a distance of about 2.7 miles. This area
is heavily fished for both rock crab and lobster. The Palos Verdes headlands are
also very important to the shellfishery. Abalones are taken offshore from Point
Vicente to White Point, as are lobsters. Lobsters are also taken off Dume Cove,
Malibu Point, the Marina Del Rey breakwater, and Santa Monica and Leo Carillo
Beach State Parks.

The majority of crabs and lobsters in Orange County are taken just outside
the marine life refuges near Dana Point, the Laguna Coast and south of Newport.
Lobsters-are also taken in the scattered kelp beds off San Clemente. 68/

The La Jol la and Point Loma kelp beds in southern San Diego County are the
most important mainland fishing grounds for lobster and abalone. 69/ Some rock
crab is taken there as well. Lobster is also taken at scattered iTtes offshore
of San Onofre, north of the Santa Margarita River, Agua Hedionda Lagoon, south of
Del Mar, and San Elijo State Beach.

Lobster and abalone are also taken around-the islands and on the offshore
banks, though the crab fishery has not yet been developed there. Commercial lob-
ster and abalone boats concentrate entirely around Santa'Rosa and Santa Cruz
Islands, but are restricted to the south side of Anacapa, the seaward side of
Santa Catalina, and the west side of Santa Barbara by the Department of Fish and
Game. San Clemente and, to a lesser extent, San Nicholas are fished heavily
except their north ends, which are restricted by the Navy. Cortes Bank is also
fished commercially for lobster and abalone. 70/

The two most important mainland areas for commercial shellfishing in the
Southern California Bight.-!- the western Santa Barbara Channel and offshore from
La Jolla to-Point Loma in San Diego -- are-among those most threatened by oil and
gasactivity. The Santa Ynez unit stretches from west of Point Conception to
Capitan, while the Department of Interior is studying an additional 52 tracts in
the western Channel and north of Point Conception for possible sale. Industry
pressure to lease these areas is high. The threat to the San Diego shellfishing
grounds is less only in terms of scale: 13 tracts off the La Jolla/Point Loma
region have been selected for inclusion in the EIS for OCS Lease Sale #48,
scheduled for March, 1978.-

1 The northern Channel Islands all have numerous leases either to the north
or south, and three-isolated leases lie to the west of Santa Barbara Island,
where commercial shellfishing is concentrated. None of the above leases, however,
had yet been developed. Leasing has also taken place on Cortes Banks, but there
are no commercial discoveries there yet.

OFFICIALLY DESIGNATED
UNIQUE BIOLOGICAL ENVIRONMENTS
Officially recognized "unique biological environments" are protected by

.335

the state or federal government from certain perturbations that could diminish
their biological value. The purpose and adequacy of the protected status afforded
these areas are discussed here, together with their vulnerability to oil spills.

The State of California has three categories of protected environments:
Areas of Special Biological Significance, State Oil and Gas Sanctuaries, and Eco-
logical Reserves and Marine Life Refuges.

The Federal government administers one category of unique biological environ-
ments in the Southern California Bight -- National Monuments, under authority of
the National Park Service (Department of the Interior).

Two additional categ ories have been established pursuant to federal law, but
as yet no geographical areas have been designated: these are Marine Sanctuaries
and Estuarine Sanctuaries.

M A R I N E S A N C T U A R I E S

The Marine Protection, Research and Sanctuaries Act of 1972 authorizes the
designation of marine sanctuaries in ocean waters from the near high tide line to the
outer edge of the Continental Shelf. Once a marine sanctuary has been designated,
no federal license, permit, or, presumably, lease can be qranted for activity
within the sanctuary without the Secretary of Commerce's certification that such
activity will not be inconsistent with the purposes of the Act.

The Secretary of Commerce should designate the waters within twelve miles of
the Channel Islands as a marine sanctuary in order to protect their value as a
habitat for endemic marine species and as foraging grounds for seabirds and
pinnipeds.

E S T U A R I N E S A N C T U A R I E S

Section 312 of the Federal Coastal Zone Management Act provides the Secretary
of Commerce with the authority to award matching grants to coastal states for the
acquisition and development of estuarine sanctuaries. The main intent of this
program is to ensure undisturbed areas for scientific research and public educa-
tion on the ecological relationship of estuarine systems. The only candidate area
in southern California is-Upper Newport Bay, which is not threatened by OCS
development.

N A T I O'N A L M 0 N U M E N T

To be a part of the National Park System, a natural area must be an expanse
or feature of land or water of such scenic and scientific value and quality as to
merit preservation as a national park, national monument, or national preserve.
The eight Channel Islands clearly meet these criteria: all are of primary ecolo-
gical significance because of their location astride a major biogeographic tran-
sition zone of the Pacific Coast, the Point Arguello-Point Conception break. The
Channel Islands support species of terrestrial flora and fauna not found on the
mainland, while in their intertidal and subtidal areas are found many unique 10
endemics and an abundance of diverse tidepool plants and animals. Importantly,
the islands also provide refuge for animals with low tolerance to human
disturbance.

Channel Islands National Monument, including only Santa Barbara and Anacapa

336

islands, was established by presidential proclamation on April 26, 1938. However,
because of the unique historical, biological, ecological, archeological, and pale-
ontological values present in a relatively undisturbed setting, there have been
subsequent proposals-to create a Channel Islands National Park'including Santa
Barbara,.Santa Rosa, San Miguel, Santa Cruz, and Anacapa islands.

San Miguel Island is administered-jointly by the Department of the Navy and
the Department of the Interior pursuant to a memorandum of agreement between the
agencies dated May 7, 1963, recognizing the.importance of the Department of the
Interior's participation in the "...protection and study of these priceless
national possessions" (San Miguel and the smaller adjacent Prince Island).

An amendment to that memorandum, dated August 21, 1976, states that "...in the
event the Department of-the Navy determines it no longer requires the use of the
islands, the USDI, National Park Service, shall seek authorization for the islands
to be preserved and protected indefinitely, a unit Within the National Park
System." Thus, if the,Navy.@relinquishes jurisdiction of San Miguel, it will
likely become part of,Channel Islands National Monument.

The intent of the National Monument designation is best embodied in the
language of the-enabling Act that established the National Park Service in 1916
and remains a principal National Park,@Service goal today:

The service thus.established shall promote and regulate the use of the
federal areas known as national parksi monuments, and reservations....by
such means and measures -as conform to the fundamental purpose of the
said parks, monuments and reservations, which purpose is to conserve
the scenery and the natural and historic.objects and thewildlife
therein and to provide for the enjoyment of the same in such manner
and by.such means as will leave them unimpaired for the enjoyment of
future generations. 71/

In,May 17, 1976i comments to the Bureau of Land Management regarding the call
for nomi,nations for OCS Lease Sale #48, the National Park Service stated that if
subsequent exploratory drilling and/or-development occurs on tracts nominated,
especially those adjacent to San Miguel and Santa Barbara Islands, "Channel
Islands National.Monument may experience adverse visual, recreational and wildlife
impacts." The U.S. Fish and ViTdlife Service also expressed concern, pointing out
that a.study of calculated slick transport-for-the Channel. Islands area conducted
for the@Western Oil and Gas Association indicates that Santa Barbara Island would
very-likely be affected by oil spills-occurring west and northwest of it. 72/
They,suggest.that an ecological buffer.zone is desirable around all of the Channel
Islands, and that the two isl,ands in greatest.need of protection from possible
@adverse effects of OCS Leas-e Sale #35.are San Miguel and Santa Barbara.

As the intensity of petroleum activity builds in,the Southern-California
Bight, strong measures must be taken to-protect these vital-and irreplaceable
natural resources. A.Channel Islands National ParkAncluding San Miguel, Anacapa,
Santa Rosa, Santa Barbara, Santa Cruz,, and San Nicholas Islands should be created

337

by Congress. The legislation should provide appropriate restrictions to insure
well-managed public access as well as protection of associated marine and terres-
trial species.

The Secretary of Commerce should designate the waters within twelve miles of
all the Channel Islands as a marine sanctuary under the provisions of the Marine
Protection, Research, and Sanctuaries Act of 1972 (PL 92-532) in order to protect
their value as habitat for seabirds, pinnipeds, and marine flora and fauna.

S T A T E 0 1 L A N D G A S S A N C T U A R I E S

State offshore lands extend from the mean high-tide line for a distance of
three geographical miles offshore and include all lands within that limit leased
for oil and gas exploration and development, those available for leasing, and
those located within codified sanctuaries specifically excluded-from oil and gas
leasing. The California State Legislature has designated these oil and gas sanc-
tuaries to prohibit oil development in what are regarded to be critical offshore
areas. 73/

The Public Resources Code of California requires that development of publicly-
owned mineral resources is not to be undertaken at the expense of environmental
values, and Sections 6871.1 and 6871.2 exclude certain state-owned offshore lands
from petroleum leasing or exploration. These sanctuaries were established under
Chapter 1724, Statutes of 1955 (the Cunningham-Shell Tidelands Act) and are admin-
istered by the State Lands Commission. 74/ This Act expressed the philosophy that
oil and gas could be developed compatibTy' with other uses of coastal and nearshore
areas. Sanctuary areas were established in sensitive regions in which leasing was
excluded except when oil and gas underlying the sanctuaries might be subject to
drainage by wells on adjacent lands.

Although no federal leasing can-take place in Oil and Gas Sanctuaries, the
State could be forced to open up such an area for a drainage sale if adjacent
leasing threatened the State's interests. Therefore, the Commission has continued
to recommend that buffer zones, such as those presently in existence near Santa
Barbara, should be established and maintained adjacent to sanctuaries. Without
adequate buffer zones, the protected status of State Oil and Gas Sanctuaries is
seriously threatened.

Figure 6 shows that Oil and Gas Sanctuaries cover all
submerged state lands in southern California not previously leased by the state,
with the exception of Santa Barbara and San Nicholas Islands. Protected status
should be extended by the Legislature to include these two islands, especially
Santa Barbara because of the federal leases adjacent to it.

A R E A S 0 F S P E C I A L B 1 0 L 0 G I C A L S I G N I F I C A N C E
(A S B S)

The State Water Resources Control Board seeks to maintain water
quality in-Areas of Special Biological Significance (ASBS), defined as
those areas containing biological communities of such extraordinary, even though
unquantifiable, value that no acceptable risk of change in their environments as
a result of man's activities can be entertained. The State and Regional Boards
prohibit the direct discharge of wastes into an ASBS or its immediate vicinity,
with the exception of vessel wastes, dredging, or the disposal of dredging spoil.

338

FIGURE 6:
OIL AND GAS SANCTUARIES

DEL
NORTEI STATE OF CALIFORNIA
S IS KIYOU MODOC
STATE LANDS COMMI-SSION

STATE LANDS DIVISIGN

TRINITY SHASTA LASSEN
mum I I
BOLDTI
L
I - OIL AND GAS SANCTUARY AREAS
L
TEHAMA PLUMAS
L r--
MENDOCINOkG---@ BUTTE ERRA LE-G END
LENN
@c"z7s A J N@EVA2A ---I EXISTING SANCTUARIES
PLACER
LAKE %
r-A
AREAS ADDED AFTER
LO EL DORA'-:-@"
SONOMA ID 0 FEB-1969
A PA ALPIN@\@-

C7
C A N
ONTRA QUIN
NCOSTA, /TUOLUMNE MONO
SAN FRANCISCO
4, /9TANISLAU14;-'@MARI POSA@'
r @01 I .\ /@Ll
SANTA
C'LARA IL@ ED
MERC
MADERA
FRESNO.
44,
j INYO

TULARE

MONTEREY KINGS

SAN LUIS L,
OBISPO KERN

SAN BERNARDINO.
SANTA
BARBARA LOS
IVENTURA ANGELES,

ORANGE RIVERSIDE

0 50 too

SCALE IN MILES SAN DIEGO IMPERIAL

339

23-76658

Wastes presently being discharged into ASBS are being phased out or required
to comply with regulations preventing waste substances in detectable levels.
Discharges outside the designated boundary are required to be monitored to demon-
strate that the effluent is not detectable within'the ASBS. 75/

Though the intent of this designation is to protect marine life from waste-
water discharges, petroleum discharges into an ASBS would be included, according
to an interpretation by the Bureau of Land Management in the final EIS for OCS
Lease Sale #35:

The existence of communities of such high value that the discharge of
-any pollutants into the area is unacceptable, puts a responsibility on
other potential polluters- to follow the spirit of the law. Any pollu-
tion resulting from offshore oil activities@which enters an intertidal
area@or@near-shore area.,designated as an ASBS would be unacceptable
according to the inte'nt of-this law, and the State Water Resources
Control Board has indicated that any discharges or other forms of
detectable pollution resulting from OCS leasing which enter ASBS would
,fall under their jurisdiction. Even a small spill would greatly
impact an ASBS if it went ashore, because a form of pollution would
involve an unacceptable risk in accordance with ASBS law. (Emphasis
added)

ASBSs are not evenly distributed along the coast. All mainland ASBSs are
found in the three southern counties (Los Angeles, San Diego,@and Orange), and
all appear to be areas that were threatened with overuse. ASBS boundaries are
designated, however, around all of the offshore islands -- to a distance of one
nautical mile offshore or to the 300-foot isobath, whichever is greater -- except
for Santa Catalina, of which only selected portions of shoreline and surrounding
waters have ASBS status.

E C 0 L 0 G I C A L R E S E R V E S A N D M A R I N E L I F E
R E F U G E S

Because of the value, scarcity, and vulnerability of rock intertidal area's
particularly in southern California where they exist only in limited and widely
dispersed coastal sites -- the Legislature and the Fish and Game Commission have
established marine life refuges and reserves to protect intertidal communities.
Protection is limited to restrictions on the taking.of marine invertebrates and
plants, though the definition of a reserve refers more broadly to land or land/
water areas preserved in a natural condition for.scientific study and for the bene-
fit of the general public in,-observing native flora and fauna. 76/

In order to assure adequate protection, Smith and Johnson maintain that,'
"Establishment of marine reserves should exclude many uses including, but not
limited to, harbor development, fishing, outfalls and pipelines..." (emPhasis
added). 77/ Such broad protection, however, is not now afforded. In practice, since
the Fish and Game Commission and the Legislature have extended protection to
marine invertebrates along the entire California coast between the high tide mark
and 1,000 feet offshore, the regulations for adjacent "unprotected" waters differ
.only slightly from those for marine reserves. Thus, while the marine life refuge
and classification remains a testimony to the value of an area and prevents re-
creational overuse, it still does not afford legal protection against possible
degradation from industrial development either inside the reserve boundary or
beyond.

340

There are fourteen areas in southern California with reserve or refuge status.
Orange County has the lion's share with nine; Santa Catalina Island and San Diego
each have two; and, Los Angeles has only one refuge. Santa Barbara and Ventura
counties have no areas with this protected status, because their unique intertidal
areas have not been subjected to pressures as great as those in the southern three
counties. All of the refuges and reserves in Orange County, Bolsa Chica, are
potentially threatened by the development of leases in San Pedro Bay. Point
Fermin Marine Life Refuge, while not directly menaced by OCS leases, is just north
of Los Angeles and Long Beach Harbors, and thus is threatened by tanker traffic in
the harbor Vicinity. San Diego and La Jolla ecological reserves will be vulnerable
to oil spill damage only if leases off San Diego that will be included in the EIS
are ultimately sold.

It is apparent that the special status of marine life refuges and reserves.
offers little protection or legal recourse from an oil spill, but rather singles
them out as areas to be given priority in oil spill contingency planning.

341

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lo ll 12 13 KLOMETERS F4-0-@ POINT CONCEPTION TO
10 11 12 MILES I M GATO
NORTH SCALE 1:62,5M CONTOUR INMWAL: 20 FEET ACRES offim Of
SENSITIVE RESOURCES INVENTORY o c 9'P'R&iEcr
1977

- - - - - - - - - - - - -

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lo 12 13 FULOMETERS FF-1 SAN AUGUSTINE TO 2
41% 10 11 12 MILES I M SACATE
NORTH SCALE 1:62,500 COWOUR 11 ACRCS or-., Ph=10=
SENSITIVE RESOURCES INVENTORY OCS PMXJECT
,9"

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lo 11 12 13 KJLOMETERS GAVIOTA TO 3
10 11 12 MILES LENTO
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET , 6Wu
SENSITIVE RESOURCES INVENTORY OCS PWJECT

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lo 12. 13 KILOMETERS FZ-1 TAJIGUAS TO 4
10 12 MILES I fq CAPITAN
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET . ACRES
SENSITIVE RESOURCES: INVENTORY
OCS PRWECT
1977

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NOTE: Pinniped haul-out sites are located at
Naples/Aminoil Beach and at Devereaux
Slough/Coal Oil Point.

10 11 12 13 KJLOMETERS; F4_0___j NAPLES TO 5
10 11 12 MILES I fq COAL OIL POINT
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET ACRES C11i. .1 R@9M=IdFl=
SENSITIVE RESOURCw'f'ES INVENTORY OCS PRWECT
1977

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NOTE: Rare and Endangered Species Habi-
tats are located at Goleta Slough; the en-
dangered species are the Light-Footed Clap-
per Rail and the Belding's Savannah
Sparrow.
A pinniped haul-out site is located at Goleta
Rocks near the mouth of Goleta Slough.

10 11 12 13 KILOMETERS GOLETA 6
10 11 12 MILES 0
NORTH -SCALE 1:U,5W CONTOUR INTERVAL @ . ACRE Off@ f F19XM9=1A
SENSITIVE RESOURCES INVENTORY OCS PROJECT
i977

S A--@@A

00
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0,000*
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00*00*00 0*900

1
lo 12 13 KJLOMETERS SANTA BARBARA 7
% 10 11 12 MILES
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET ACRES
SENSITIVE RESOURCES INVENTORY' OCS PFOJECT
1977

_J
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0
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0
0
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0
0
0
0
0
0
0
0
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NOTE: Rare and Endangered Species
Habitats are located at El Estero and
Carpinteria; the endangered species are the
Light-Footed Clapper Rail and the Beldings
Savannah Sparrow.

A pinniped haul-out site is located near the
Chevron Oil Pier.

10 It 12 13 IQLOMETERS R5_1 SUMMERILAND TO
10 11 12 MILES 1 1101 CARPINTERIA 8
NORTH SCALE 1:62.500 CONTOUR INTERVAL: 20 FE ACRES 4;@.Id`9=
SENSITIVE RESOURCES INVENTORY OCS PWJECr

1, A. >wr

W
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lo ll 12 13 KJLOMETLF!S r40@ RINCON POINT TO 9
1
10
0 12 MILES 0 PITAS POINT
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET
SENSITIVE REWOURCES INVENTORY OCS PROJECT
1977

lo ll 12 13 I(ILOMETERS F4-0--l VENTURA 10
10 12 MILES I [qO
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET ACRES Offce of PM@@ Gff@
@ @j
SENSITIVE RESOURCES INVENTORY OCS PR()JECT

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10 11 12 13 KJLOMETERS F407 PORT HUENEME
10 11 12 MILES
NORTH SCALE 1:62,WO CONTOUR INTERVAL: 20 FEET ACRES oflmf Pl=d9=
SENSITIVE RESOURCES INVENTORY OCS PWJECT

@7
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NOTE: Rare and Endangered Species Habi-
tats are located at Mugu Lagoon; the an-
dangered species is the California Least Torn.

A pinniped haul-out site is located at the sand
flats in Mugu Lagoon.

10 11 12 13 KJLOMETERS POINT MILIQU 12
10 11 12 MILES I 1 0
NOM'Fi SCALE 1:62,500 CC1=UR IN'MRVAL: 20 FEE Caflk-
ollm d %, ;.9=
SENSITIVE RESCIURCES INVENTORY OCS PROJECT
1977

V
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lo 11 12 13 KJLOMETERS F470-1 SEGUIT POINT 13
10 11 12 MILES I F01
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET ACRES Office of I cl=
P, -d9=j
SENSITIVE RESOURCES INVENTORY OCS PRWECT
1977

C 7
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lo ll 12 13 KJLOMETERS F40 POINT DUME 14-
10 11 12 MILES I F01
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET ACRES Offm f P9v.-41=j
SENSITIVE RESOURCES *INVENTORY OCS PROJECT
19,n

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lo 11 12 13 KILOMETa 40M MALIBU BEACH TO
1
10
4*1* 10 11 12 MILES 0 LAS FLORES 15
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET
S @ Offi..f P9X-.,d9t=*
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1977

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lo ll 12 13 KILOMETERS f4O--l TOPANGA BEACH TO 16
10 11 12 MILES I [qO SANTA MONICA
NORTH SCALE 1:62= CONTOUR INTERVAL: 20 FEET ACRES
offm NR_@* %GF? g
SENSITIVE RESOURCES INVENTORY OCS PROJECT
1977

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10 11 12 13 KJLOMET@Fr. F40 --I VENICE TO 17
10 11 12 MILES I n MANHATTAN BEACH
NORTH 1:62,5W CONTOUR INTERVAL: 20 FEET . ACRES O"k. ],gx-.w9=
SENSITIVE RESOURCES INVENTORY OCS PWJECT

p N@z

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REDONDO BEACH

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lo ll 12 13 KILOMET 40 HERMOSA BEACH TO
a F 18
0111% 10 11 12 MILES I F01 POINT VICENTE
NORrH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET . ACRES Offs.
SENSITIVE RESOURCES INVENTORY OCS PROJECT
1977

t1il-i- 0777M 4@l -!"41,
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lo 12 13 KJLOMETERS fZF-l PORTUGUESE BEND TO
10 11 12 MILES 1 1101 LOS ANGELES HARBOR 19
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET _ ACRES
SENSITIVE RESOURCES INVENTORY OCS PRIJECT
ign

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NOTE: Rare and Endangered Species Habi-
tats are located at Terminal Island; the en-
dangered species is the California Least Tern.

.10. 11 12 13 KJIIOMETERS LONG BFEACH
10 12 MILES @O 20'
r q10
NORTH SCALE 1:62,500 CONTOUR WTTERVAL: 20 FE W. P9M -.w9=
SENSITIVE RESOURCESINVENTORY OCS PRWECT
19TT

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HUNTINGTON BEACH

@"-@`-NOTE: Rare and Endangered Species Habi-
tats are located at Anaheim Bay and Seal
.rBeach; the endangered species are the Light-
Footed Clapper Rail and the Belding's
avannah Sparrow.
5EA

1% 10 11 12 13 KILOMETERS. F40-1 SEAL BEACH TO .21
10 11 12 MILES I F01 HUNTINGTON BEACH
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET ACRES PaW"=Wf--.A
SENSITIVE RESOURCES INVENTORY OCS PRWECT
1977

4. Qq A
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........................

NEWPORT BEA

--------------

0
0
0
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0
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NOTE: Rare and Endangered Species Habi-
tats are located at the wetlands of the Santa
Ana River and at Upper Newport Bay; the
endangered species are the California Least
Tern and the Light-Footed Clapper Rail.

10 11 12 13 KJLOMETa F40 NEWPORT BEACH 22
41% 10 @ 11 12 MILES I JqO
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET ACRES Of I i. 0 R9V%=d'="
SENSITIVE RESOURCES INVENTORY OCS PRWECT
197-7

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lo 12 13 KJLOMIETERS LAGUNA BEACH 23
10 12 MILES 1 1101
NORTH SCALE. 1: 62,500 CONTOUR INTERVAL: 20 FEET . O"im of 4@wld=c@h'
SENSITIVE- RESOURCES, INVENT-ORY.' 0 C S PRWECT
1977

-6,644 4 liN
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10 12 13 rjl_OMET@RSS r4_0_@ MUSSEL COVE TO 24
#111* 10 11 12 MILES I F01 SAN CLEMENTE
NORTH SCALE 1:62= CONTOUR INTERVAL: 20FEET ACRES 9=
SENSITIVE RESOURCES INVENTORY OCS PROJECT
1977

0-
42
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0
0
0
00
0
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NOTE: A pinniped haul-out site is located at 00
San Onofre Slough. 00000

10 11 12 1.3 IKILOMET= FF-1 SAN MATEO POINT TO
10 11 12 MILES I F01 SAN ONOFRE 25
NORTH SCALE 1:62,500 CONTOUR INTERVAL; 20 FEET ACRES
S F1=_.C=_..
ENSITIVE RESOURCES INVENTORY OCS PRWECT
1977

0 n17
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7
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NOTE: A pinniped haul-out site is located at 0
Las Flores Slough.
0

10 11 12 13 KILOMETERS rZ__j LAS PULGAS CANYON 26
10 11 12 MILES I F01
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET ACRES
S Offim f P91v .1d,=.9
ENSITIVE RESOURCES INVENTORY OCS PWJECT

XA
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0
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0
0
0
0
0
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NOTE: Rare and Endangered Species Habl-
tats are located at the wetlands of the Santa
Margarita River and at the Buena Vista
Lagoon; the endangered species is the 00
California Least Tern. 0
0
0
1

10 It 12 13 KJLOMETERS F4-0-1 OCEANSIDE TO
10 11 12 MILES I [I CARLSBAD 27
NORTH SCALE 1:62,500 CONMUR INTERVAL: 20 FEET ACRES
d
SENSITIVE RESOURCES INVENTORY Off m P1. PW)JEC IT
OCS
1117

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fi '7, 0
0
0

0
0

0
0
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0
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0
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0
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0
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0 7
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0
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0

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0
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0
0
0 V
0
0
0
0
0
0
0
0
0
0

0
NOTE: Rare and Endangered Species Habl- 0
0
tats are located at Los Penaquitos; the 0
endangered species are the Light-Footed 0
0
Clapper Rail, the California Least Tern, and 0
the Belding's Savannah Sparrow. 0
0
0
0
0
0

10 11 12 13 KILCMETERS F40 -1 SOLANA BEACH TO 29
10 11 12 ME-S I F01 TORREY PINES
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET ACRES
oif@ Of C@=9=j
SENWQITIVE RESOURCES INVENTORY OCSp"ROJECT
1977

%
i"J@
ooo
:0
hMO; k
1, v
MAU.-

9 U UZU

s' V vori
MR SMU
xv, vs
% lp
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0
0
0
0

TW7
0
0

0
0
0
0
0
0
NOTE: Rare and Endangered Species
Habitats are located at Mission Bay; the en-
dangered species are the California Least
Tern and the Light-Footed Clapper Rail.

10 11 12 13 KJLOMETERS [Z-_1 POINT LA JOLLA TO 30
10 11 12 MILES I F01 MISSION BAY,
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET . ACRES offiw cwft- 9=1
SENSITIVE RESOURCES INVENTORY'.'- 0 C 9 'PR6j ECT
1977

25--76658

LaL
133rOUd SOO AUOJLN3ANI S33MOSM 3AIIISN3S
lp
S380V i3mi oz:wmaw anamo 009'2:4:L 31VOS HMON
0-1 MIN z I L 1 0
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---------------

T MW

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SAN DIEGO
A V

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------ - ----

4-
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tA

11
0000000
0 IRK cx

7
am

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0

NOTE: Rare and Endangered Species Habi-
tats are located at the tidal flats of San Diego
Bay; the endangered species are the Light-
Footed Clapper Rail, the California Least
Tern, and the Belding's Savannah Sparrow.

#*t4,* 10 11 12 13 KILOMETM F40___j SAN DIEGO 32
10 11 12 MILES I fT01
NORTH SCALE 1:62,500 CONTOUR INTIERVAL: 20 FEET ACRES
S offim Of Rg=q=j
ENSITIVE RESOURCES INVENTORY OCS PIROJECT
1977

0
0
0
0
0

0
0
0
0
0
0
0
0
0
0
0
0
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0
0
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0
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0
0
0
0
0
000000000000000000000000

NOTE: Rare and Endangered Species Habi-
tats are located at Lower San Diego Bay and
at the wetlands of the Tijuana River; the
endangered species are the Light-Footed
Clapper Rail, the Belding's Savannah Spar-
row, the California Brown Pelican, and the
California Least Tern.

10 It 12 13 KJLOMETERS F4Z::] IMPERIAL BEACH 33
10 11 12 MILES 1 1101
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET . ACRES offim .1 P=-.9=
SEKIS TIVE RESOURCES INVENTORY OCS PWJECT
1977

00 0
00000 000,0
0,
66

a Wit- P-k

0 Ri@h.,d- R-k

.......... ....................
v

goo
0
C-1jeRmk
W-f %
4 %

vy,

@ 71-N.4-
......... . ........
................... ..............................

006000 000009% 0
00 9960600 00

NOTE: Rare and Endangered Species habi-
tats are located on San Miguel Island; the
endangered species is the California Brown
Pelican; the rare species are the Guadalupe
Fur Seal and the Island Fox.

11 12 13 15 17 KILOMETERS fR;T] SAN MIGUEL ISLAND 34
4** 10 11 12 13 14 15 Mil ES Ljjd
NORTH SCALE 1:165,000 CONTOUR INTERVAL: 20 FEET ACRES
SENSITIVE RESOURCES INVENTORY 0"'U'P96JECT
1977

10 3000 00
0
00000
0 000 00cpao 0 'e-POS-50,
10 @010C
000000000000000 0 0
0 0
00 0
-00000
-0
000 0
0
/401@0@ ......... % 0
60 ............... 0
.................... AC. 0
0
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0

P 94.i
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..... ..........................
Vill
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.......................

0OOC
C)OOO ()00
0000000000
.............
0 000 ................. 0
0 0
0
000
00 00CO000000000000000- 00
0-00,00000
00000 00
0000

NOTE; Rare and Endangered Species Habi-
tats are located on Santa Rosa Island; the
endangered species is the California Brown
Pelican; the rare species is the Island Fox.

11 12 13 15 17 KJI-OMETERS WTI SANTA ROSA ISLAND 35
011% 10 11 12 13 14 15 MILES UM
NORTH SCALE 1:165,000 CONTOUR INTERVAL: 20 FEET ACRES office of cl%mom",
SENSITIVE RESOURCES INVENTORY OCS PROJECT
J"

.....................
,%

%
%
0

0
1'c i`.@

0 0
%
0

0
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0
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0
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0
& NO' 0
0 0
" SM-1W
0
0
R: 0
0
0

0
0 0

0
0 0
0
0
0
0
0
0

0 . .........
0
0
0
0 NOTE: Rare and Endangered Species Habi- 0
10 tats are located on Santa Cruz Island; the0
0 0
0 endangered species is the California Brown0
Br
0 Gu Ip
Pelican; the rare species are the Gudalu e

11 12 b 15 17 KILOMErEIRS. fm_1 SANTA CRUZ ISLAND 36
10 11 12 13 14 15 MILES 1 1401
NORTH SCALE 1:165,000 CON7MR INTERVAL: 20 FEET ACRES
0M.&M 1.id
SENSITIVE RESOURCES INVENTORY OCS PROJECT
1977

00C)o0ge 6960
00, 00,
GQ'0 66,
01,
00 ego
000 000 a 000 ea
a
00
go
0
('00
000

..... .............................. ........................

...............

........... .
.......... ................... . ...... ............ ..............
. ....................

"8600
(D 600%
a
0 0 0000 00 0690
'0 00000
'0000000,
00000000 0
00000
00000 0 0
000 000000000000 00000060000000000000000000000 000000, 0000 000

NOTE: Rare and Endangered Species Habi-
tats are located on Anacapa Island; the en-
dangered species is the California Brown
Pelican.

Anacapa Island Is administered as a National
Monument by the National Park Service.

10 11 12 13 KJLOMETERS F4Z-_-] ANACAPA ISLAND 37
10 11 12 MILES I I 1v
NORTH SCALE 1:62,500 CONTOUR INTERVAL: 20 FEET AMES offim of R=9=
SEINISTIVE RLEWOURCES INVEWORY OCS.PRWECT
1977

ago agog,**
a ago ago*,**

a
0

......................................
0

0
h.g poc 0

0
a
00

0
suhl Isfa.1d 0

................................

a
0

00000
a

00
00000 00000 000000000000000000000

NOTE: Santa Barbara Island is administered
as a National Monument by the National Park
Service.

11 12 13 15 17 KILOMETERS SANTA BARBARA ISLAND
Olt%, 10 11 12 13 14 15 -MIL-ES
NORTH SCALE 1:165,000 CONTOUR INTERVAL: 20 FEET ACRES
SENSITIVE RESOURCES INVENTORY OCS PROJECT
1977

D00000008000000000 0 0 000000000
0

0
00
.............. ................................... 0000000000
00
0
0
0
0
0
0
00000000
0000000
M
N
ship A-*
000
000 000
0
0
0
0
00

0
0

................... 0
v,
0
0
0
0
0
0

00000000 0
0
I...... .. kk-
0000
0
0
0
0
v".Y
0
0
0
0
0
47
0
0 .........
0 @7 -m

0
0
0
Z:-
0

0
0
0 ............

0
0
0
0
0
0

0
000000000
000000
0000000000000000000000000000000 00000C)OOO 0
000000 1000000000 0 000

NOTE: Rare and Endangered Species
Habitatsare locateclon SantaCatallna Island;
the rare species are the Guadalupe Fur Seal
and the Island Fox.

10 11 12 13 KJLOMETERS P3--j SANTA CATALINA ISLAND 39
10 11 12 MILES
NORTH SCALE 1:62,500 CONTOUR INTERVAL- 20 FEET
SENISITIVE RESOURCES INVENTORY OCS PRWECT
1",

_-1-15-V 0
COO, 0000000000
000
......................

0
0

0
-0
w(D

0 77

% QD
0
G

...........

............ .
................................ ....... ......

000,00
a
a 00
00 0006 00000 (2)0 0000 00
0 000000000000000

NOTE: Rare and Endangered Species Habi-
tats are located on San Nicolas Island; the
rare species is the Island Fox.
0
0
0

11 12 13 15 17 KILOMETERS POE) SAN NICOLAS ISLAND 40
10 11 12 13 14 15 Mil ES L_W
NORTH SCALE 1:165,OW COKMR INTERVAL: 20 FEET ACRES 01fi.
SENSITIVE RESOURCES INVENTORY OU'PEJECT
'977

000000 000000000 0 000,
0 0

........... . ....................0
NW Harbpr Wof 0

j
vj. R,@r 0
0
04,
j
0
ta

0
0
0
0

0
0
0
0
0
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% 0

% 0
% 0
%I %1. 00
0 0
% 0
% 0
%
0
% %
% 0
0
%
0 0
00

00
00
% 0
0

0
if 0,
0
0
0 0
0 %%
CD
ox- 0
0
0
0
0 0,
0
0
%% 0
0 0()
0
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'i p C
0
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0
0
0 0
%%
0
0
0

0
0
0
0
00 ......................................01
000 0
% 0
00
80 %
030C)OCC Goo% ............ 00
0
(Do a

NOTE: Rare and Endangered Species
Habitats are located on San Clemente Island;
the rare species are the Guadalupe Fur Seal
and the Island Fox.

11 12 13 15 17 KILOMETEFIS PEI SAN CLEMENTE ISLAND 41
01,11k 10 11 12 13 14 15 MILES 1 10
NORTH SCALE 1:165,000 CONTOUR INTERVAL: 20 FEET ACRES offim d -9@lv mcg=
SENSITIVE RESOURCES INVENTORY OCS PRWEL-r
1977

.FOOTNOTES

1. K. S. Norris, et al., The Distribution, Abundance, Movement, and Repro-
.duction of Birds, Cetaceans, and Pinnipeds in the Southern California Bight: A
.Six-Month Progress Report to the BLM-OCS Program, 1975.

2. U.S. Bureau of Land Management, Final Environmental Statement, OCS SaIe #35,
1975.

3. Norris, 9R. cit.

4. J. Lindstedt-Siva, Oil Spill Response Planning for Biologically Sensitive
Areas in the Santa Barbara Channel (Atlantic-Richfield Co.), 1976.

5. U.S. Bureau of Land Management, op. Cit.

6. Ibid.

7. U.S. Department of the Interior, Fish and Wildlife Service, "Endangered and
Threatened Wildlife and Plants -- List of Species," Federal Register, XLI
(September 30, 1976), 191.

8. Ibid.

9. Marine Mammal Commission, memo to Mr. C. Berklund, Bureau of Land Manage-
ment, re: Comments on Leasing in the Outer Continental Shelf -- Offshore California
September 8, 1976.

10. California Department of Fish and Game, Draft Atlas of Prominent Southern
California Marine Resources, 1976.

ll.- U.S. Department of the Interior, Fish and Wildlife Service, op. cit.

12. Coastal Zone'Management, Vol. 7, No. 28 (July 14, 1976), p.4.

13. W. J. North and Carl Hubbs, "Utilization of Kelp Bed Resources-in Southern
California," Fish Bulletin 139, California Department of Fish and Game (1968).

14. California,Water Resources Control Board, Designating Areas of Special
Biological Significance and Authorizing Notification of the Regional Water Quality
Control Boards and the Environmental Protection Agency, 1974.

15. U.S. Bureau of Land Management, op. cit.

16. H. W. Frey, ed., California Living Marine Resources and Their Utilization,
California Department of Fish and Game, 1971.

17. Ibid.

18. North and Hubbs, op. cit.

19. Frey, op. cit.

20. Ibid.

21. Personal communication from Dave Hadder, Esca-Tech, to Carol Pillsbury,
OCS Project Staff.

383

22. Frey, op. cit.

23. J. W. Valentine, "Numerical Analysis of Marine Mulluscan Ranges on the
Extratropical northeastern Pacific Shelf," Limnology and Oceanography, XI (1966),
198.

24. U.S. Bureau of Land Management. op. cit.

25. California Department of Fish and Game, Coastal County Fi sh and Wildlife
Resources and their Utilization, 1973; and U.S. Bureau of Land Management, op. cit.

25. Lindstedt-Siva, oD. cit. -

27. Norris, op. cit.

28. Steven H. Smith, Report of the Preliminary Bioluical Assessment of
Tanner Bank and Cortes Bank Offshore Southern California (unpublished), 1976.

29. Quast, "Estimates of the Populations and Standing Crop of Fishes,"
Bulletin 139, California Department of Fish and Game (1968).

30. Personal communication, from Dr. Gilbert Jones, to Carol Pillsbury, OCS
Project Staff, April 6-0, 1977. See also Smith, op. cit.

31. Smith, op. cit.

32. U.S. Bureau of Land Management, op. cit.

33. Federal Register, #176, 40 (September 10, 1975), p. 42039.

34. U.S. Department of the Interior, Fish and Wildlife Service, op. cit.

35. J. Hendrickson, "Ecology of Southern California Coastal Salt Marshes,"
Proceedings of the Symposium on Plant Communities of Southern California, J. Latting,
ed., California Native Plant Society, Special Publication No. 2, p. 49.
36. California Coastal Zone Conservation Commission, California Coastal Plan,
1975; R. D. Bauer and J. W. Speth, Acquisition Priorities for the Coastal Wetlands
of California, 1974; California Department of Fish and Game, Status Report on the
Coastal Wetlands of Southern California, 1969; and California Department of Fish and
Game, Draft Atlas of Prominent Southern California Marine Resources, 1976.

37. California Coastal Zone Conservation Commission, California Coastal Plan,
1976..

38. U.S. Department of the Interior, Fish and Wildlife Service, op. cit.

39. M. Blumer, "Scientific Aspects of the Oil Spill Problem," Environmental
Affairs, I (April 1971), 54.

40. Lindstedt-Siva, op. cit.

41. U.S. Bureau of Land Management, op. cit.

384

42. Ibid.

43. Lindstedt-Siva, op. cit.

.43a. U.S.. Bureau of Land Management, op. ci.t.-,

44. U.S. Department-of the Interior, Fish and Wildlife Service, op. cit.

45. U.S. Bureau of Land Management, op. cit.'

46. U.S. Department of the Interior, Fish and .Wildlife Service, op. cit.

47. See, for example, R..C. Erickson, "Oil Pollution and Migratory'Birds,"
.XVIII, Atlantic Naturalist (1963); J. W. Aldrich, Review of the Problem of Birds
Contamin-ated'by Oil and their Rehabilitation, U.S. Department of.the Interior,
Fish and Wildlife Service, Bureau of Sport Fisheries and Wildlife, Resource
Publ.ication 87, 1970; R. Hartung, "Energy Metabolism in Oil-Covered Ducks," XXXI,
Journal of Wildlife Management (1967), and "Some Effects of Oiling on Reproduction
of Ducks," XXIX, Journal of Wildlife Management (1965); R. Hartung and G. S. Hunt,
"Toxicity of Some-Oils to Waterfowl," XXX, Journal of Wildlife Management (1966);
R. B. Clark, "Oil PollutTon and the Conservation of Seabirds," Proceedings of
.International Conference on Oil Pollu'tion of the Sea (Rome), 1968, pp. 76-112;
and J.. C. Chubb, "Observations of Oiled Birds, 1951-53," 11, Northwest Nature
(1954), 460-461.

48. U.S. Department of the Interior, Geological Survey, Final Environmental
Impact Statement, Oil.and Gas Development in the Santa Barbara Channel.Outer
Continental Shelf of California, 1976.

49. Norris, op. cit.

50. Ibid.

.51. U.S.-Department of the Interior, Fish and.Wildlife Service, op. cit.

52. Norris, op. cit.

53. California.Department of Fish and Game, Coastal County Fish, op. cit.

54. U.S. Department of the Interio-r, Fish and-Wildlife Service, "Endangered
and Threatened Wi.ldlife and Plants --.List of Species," loc. cit.; U.S. Bureau of
Land Management, op. cit.; Norris, op. cit.; personal communication to Carol
Pillsbury, OCS Project Staff, from Lee Jones, May 18, 1977; and Jones, Lee, and
Jarred M. Diamond, "Short.Time-Basis Studies of Turnover in Breeding Bird
Populations on the.California Channel-Islands," Condor, LXXVIII, (1976), 566-549.

55. U.S. Bureau of Outdoor Recreation, memo to Bureau of Land Management
regarding Proposed'Call-for Nominations of OCS Lands off California for,Possible
Oil and Gas Lease Salo #48, June 3,, 1976.

56. California Department of Fish and Game, Coastal County Fish,.op. cit.

57. U.S. Bureau of Land Management, op. cit.

58. California Department of Fish and Game,, Coastal.County Fish$ op. cit.

385

58a. U.S. Bureau of Land Management, op.. cit.

59. California Coastal Zone Conservation Commission, California Coastal
Plan, 1975.

60. California Department of Fish and Game, Coastal County Fish, op. cit.

61. Gruen and Gruen, A Socio-Economic Analysis of California's Sport and
Commercial Fishing Industries, A Report to the Resources Agency, 1972.

62. S. H. Anderson, ed., Proceedings of the National Conference on Marine
Recreation: Recreation -- Marlne@Promise., Newport Beach, California, October 2-4,
1975.

63. Frey, op. cit.

64. Ibid.

65. Ibid.

66. Personal communication from.Robert Bell, California Department of Fish and
Game, to Carol Pillsbury, OCS Project Staff, April 14, 1977.

67. California Department of Fish and Game,. Draft Atlas, op. cit.

68. Ibid.

69. Personal communication from Robert Bell, Cal.ifornia Department of-Fish and
Game, to Carol Pillsbury, OCS Project Staff, April 14, 1977.

70. Personal communication from Dick Burge, California Department of Fish and
Game, to Carol Pillsbury, OCS Project Staff, April 14, 1977.

71. 16 U.S.C. 1.

72. U.S. Department of the Interior, Fish and Wildlife Service, "Endangered
and Threatened Wildlife and Plants," loc. cit.

73. W. J. Northrop, State Lands Commission@ memo to A. J. Kline regarding:
Nominations and Comments on Offshore Bids, J.uly 1, 1976.

74. California State Lands Division, Hydrocarbon Potential of California
Offshore Lands and San Pablo Bay, 19.76.

75. California State Water Resources Control Board, Designating Areas of
Special Biological Significance and Authorizing Notification of the Regional Water
Quality Control Boards and the Environmental Protection Agency, 1974.

76. E. J. Smith, Jr., and T. H.. Johnson, "The Marine Life Refuges and Reserves
of California," Marine Resources Information Bulletin, No. 1, 1974.

77. Ibid.

386

CHAPTER 17

OIL SPILL:
PREDICTING THE UNPREDICTABLE

SOURCES @OF OIL IN OCEAN WATERS
Oil spills from offshore production activities are only one of many path-
ways for petroleum hydrocarbons into the oceans. The National Academy of
Sciences (NAS) has estimated that more than six million metric tons of oil per
year enter the world oceans from all sources. l/ Table 1, below, is taken
from the NAS study to show the relative amount7s of petroleum that enter the
oceans each year. From Table 1, it can be seen that, on a worldwide basis,
non-marine sources -- river and urban runoff from developed-or industrial
areas on land, atmospheric rainout.-- are estimated by NAS to contribute
more than half (54%) of the oil reaching the oceans. Tankers are the largest
marine source (34.9%), with natural seeps contributing an estimated 9.8'/O'.and
offshore production only 1.3%. Thus ', in terms.of the overall budget for
oil entering the oceans, oil spilled in the course of offshore operations
contributes only a small fraction of the total load.

TABLE 1:
GLOBAL BUDGET FOR PETROLEUM ENTERING THE OCEANS 2/

MILLION
METRIC TONS PERCENTAGE
SOURCE PER ANNUM CONTRIBUTIONS

Transportation 2.133 34.9
Tankers, dry docking, terminal
operation, bilges, accidents
Coastal refineries, municipal and 0.8 13.1
industrial waste
Offshore oil productions 0.08 1.3
River and urban runoff. 1:9 31.1
Atmospheric fallout 0.6 9.8
Natural seeps 0.6 9.8

Total 6.113. 100.0

26-76658 387

But oil entering the oceans from land sources, whether through river
runoff, atmospheric transport, or outfall pipes, is diluted before it reaches
the ocean and rapidly disperses once in the ocean, greatly reducing its.impact
on the concentration of petroleum hydrocarbons in any particular coastal or
marine area. Oil spills, in contrast, create heavy concentrations of oil in
comparatively small areas. The dosage or concentration of oil strongly influ-
ences the effects of oil on coastal and marine resources. For this reason,
offshore oil,spills -- despite their relatively small contribution to the total
petroleum load- are a major part of the oil pollution problem.

Table 1 provides a useful,perspective on worldwide oil pollution sources.
In the waters off southern California, however, the percentage contribution
from each source may be quite different. For example, there is relatively
little rainfall and therefore little river runoff-in southern California, so
the contribution from this.s-ource is doubtless well below the 31% noted globally.
On the other hand, much of,the coastal zone in southern California is heavily
developed, and the Los Angeles basin has about 1,200,000 B/D refining capacity,
so here the @percentage contributionJrom coastal refineries and municipal and
industrial wastes is probably greater than the worldwide 13.1%. As for the con-
tributionJrom offshore production activities, 1.3% may be a reasonable.worldwide
estimate,tut in those very few areas of the world where offshore production
occurs, such as southern C-alifornia, Texas, and Louisiana, the contribution
from this source is apt to be considerably greater than the worldwide average.
Similarly, the contribution from natural seeps in the Santa Barbara Channel may
be greater than 9.8%, while in the rest of southern California the-percentage
contribution from natural seeps may be below the estimated international average.

S 0 U R C E S 0 F 0 1 L I N S 0 U T H E R N C A L I F 0 R N I A
C 0 A S T A L W A T E R S

Table 2 presents statistics on oil spills occurring in Coast Guard
District 11 (from the Mexican border to the Santa Barbara/San Luis Obispo
County border.) during 1973-1975.

TABLE 2:
'COAST GUARD DISTRICT 11 OIL SPILLS, BY SOURCE, 1973-1975
(VOLUME IN GALLONS) 3/

1973 1974 1975
Number Volume Number Volume Number Volume

Total 820 154,826 803 899,851 809 243,289
Tankers 131 8,826 76 22,001 47 93,719
Barges '13 64 10 310 3 21
Other Vessels 228 8,213 226 16,730 243 13,625
Marine Terminals 29 9,085 .28 1,386 18 439
Other Transportation 11 16,707 21 101,349 28 24,305
.(Trucks, Trains, etc.) 249813 36 7403,899 24 47,345
Pipelines 15
Non-Transportation 46 76,195 39 13,730 58 60,299
(Tank Farms,etc.)
Miscellaneous/Unknown 347 10,946 367 3,446 388 3,536

388

The number of spills reported to the Coast Guard decli ned slightly from
1973 to 1975, while the amount of oil spilled increased substantially. Table 3
compares the relative contribution of each source with respect to the number and
volume of reported spills.

TABLE 3:
COMPARISON OFSOURCES, COAST GUARD DISTRICT 11 OIL SPILLS, 1973-1975 4/

NUMBER OF PERCENTAGE VOLUME (GALLONS) PERCENTAGE
SOURCE POLLUTING INCIDENTS OF TOTAL OF OIL SPILLED OF TOTAL

Tankers 254 10 % 124,546 10%
Barges 26 1% 395 1%
Other Vessels 697 29% 38,568 3%
Marine Terminals 75 3% 10,910 1%
Pipelines 75 3% 813,057 63%
Other Transportation 60 2% 142,361 11%
Non-Transportation 143 6% 150,224 12%
Miscellaneous/Unknown 1,102 45% 17,928 1%

Several general observations should be made about oil spill statistics. 5/
The amount of oil spilled in any incident can vary tremendously, from less than
one gallon to more than ten million gallons. Because ofthis variation, it is
not always helpful to discuss average spill size. Most spills involve compara-
tively small volumes of oil. For example, spills from "other vessels" and
"miscellaneous/unknown" sources accounted for 74% of the number of spills reported
in District 11 during that period but only 4% of the volume of oil spilled. Most
of the oil spilled during any reporting period comes from a handful of very large
.spills. For example, one pipeline spill in 1974 accounted for 55% of the total
volume of oil estimated to have been spilled in District 11 during the entire
1973-1975 period. If this pipeline spill hadn't occurred, the percentage con-
tributions in terms of volume of oil spilled would be markedly different.
Conversely, if either the 1969 Santa Barbara Channel blowout or the 1976
Sansinena tanker spills had-occurred during the 1973-1975 period, both the
overall totals and the percentage contributions of each category would be mark-
edly different.

With respect to the causes of oil spills, Table 4 presents Coast Guard data
for all reported spills on the West Coast during 1973-1975. For the spills with
known causes, human error accounted for the largest numbers. Likewise, many of
the spills attributed to other causes -- such as equipment-failure, structural
failure, vessel collisions, and vessel groundings -- also stem from human error
through poor maintenance, improper use or operation, etc.

Of particular concern to this study are the sources of oil spills that involve
the.development of oil and gas offshore of southern California. The most signifi-
cant causes of spilled oil resulting from offshore development include production
platforms, pipelines, tankers and crude oil transfer operations. These sources
of spilled oil are discussed below. In addition, the relative contribution of
oil in Southern California coastal waters caused by natural seeps is also described.

389

TABLE 4:
CAUSES OF WEST COAST OIL SPILLS, 1973-1975 -6/

Perce'nt of- Percent of
Number of Total Number of Volume Spilled Total Volume of
Cause Spills @Reported Spills (Gallons) Reported Spills

Unknown 2,975 48% 204,000 5%
Personnel Errors 1,370 22% 212,100 5.5%
Equipment Failures 885 14% 1,260,000 33%
Structural Failures 460. 6.5% 832,300 22%
Intentional Discharges 260 4% 35,500 1%
Natural and Chronic 215 3.5% 8,000 1%
Causes
Vessel Collisions 40 1% 1,156,000 30%
Vessel Groundings 20 1% 105,000 3%

PRODUCTION PLATFORMS

Thepotential for major platform spills, especially from a blowout, is
greatest during drilling operations. A blowout occurs when a well is drilled into
a zone of unexpected high pressure, and platform safeguards are unable to prevent
oil from escaping to the surface. If the,well casing is inadequate, and the strata
between the high pressure zone and the ocean floor are weak and fractured, as
was the case in the l9b9 Santa Barbara Channel blowout, oil may continue to
escape to the ocean after the well is again under control. (The amount of
oil spilled during the 1969 blowout is disputed, with estimates ranging from
10,000 to over 700,000 barrels. 7/). Aside from blowouts, major spills can
occur at platforms as a result 6T fires, explosions, vessel rammings, or other
accidents.

Once production has been achieved at a platform, minor spills can occur
at any time. The incidence of production spillage depends both on the care
of platform operators and the diligence of government inspectors. A report on
Chevron's 1970 spill in the Gulf of Mexico described the situation at that
time:

Spills varying in size from a few gallons to many barrels are endemic
to the Gulf of Mexico.... Oil appears on the Gulf waters from ... numerous
operations connected with the drilling (and) operations of the wells.
U.S. Coast Guard's reconnaissance flights report three to seven pol-
lution incidents every week, and many of these identify with the com-
pany or individual responsible. However, the cause of each incident
is not generall documented, and action to prevent a recurrence is not
often taken.

Since 1970, USGS has strengthened its spill-prevention regulations and enforce-
ment standards. As a consequence, the number of spills in the Gulf of Mexico
has dropped significantly in recent years. 9/

390

Based on historical spill data, Massachusetts Institute of Technology
scientists have calculated 10/ that for a small oil field (defined by MIT as
containing 122 MMB recover0fe oil), there is a 25% chance that at least one
platform spill larger than 1,000 barrels will occur; that for a medium oil
field (5.67 MMB recoverable oil), the probability is 70%; and that for a large
oil field @2,044 MM1B recoverable oil), the probability is over 957.. Further,
the MIT scientists calculated that if a platform spill of over 1,000 barrels
occurs, there is an 80% chance that the spill will exceed 2,380 barrels, and a
35% chance that it will exceed 23,800 barrels. ll/ It should be noted that
these predictions do not allow for improvements'in drilling procedures or
technologies, but merely extrapolate into the future on the basis of historic
spill rates.

PIPELINES

All of the crude oil produced off California is brought ashore through
pipelines. Pipeline accidents -- leaks, ruptures, etc. -- can result in minor
or major oil spills. Most pipeline spills are very small. For example, the
average size of the 1,643 pipeline spills occurring in the United States in 1971
was less than ten barrels. 121 On the other hand, the largest U.S. pipeline -
spill recorded to date, in Te Gulf of Mexico in 1967, discharged 161,UOO
barrels over ten-days. 13/ The only crude oil spill resulting from a pipeline
serving production plat7f-orms off California occurred on December 16, 1969, at
Union's Platform A, site of the blowout earlier that vear, with 900 barrels
spilled before the line could be shut down and repaired. 14/ The Dioeline sDills
shown in Table 2, preceding, for 1973, 1974 and 1975 occurred onshore and made
their way into harbor waters.

TANKERS

About 400,000 B/D of foreign crude oil are delivered by tankers at southern
California terminals. 15/ As well, much smaller amounts of crude produced from
Santa Barb'ara Channel fl'-delands leases are carried by tanker to Los Angeles Basin
and San Francisco Bay terminals. The relationship between tanker spills, tanker
arrivals, and the volume of petroleum delivered at southern California ports and
terminals is illustrated in Table 5.

Oil spillage occurs routinely during tanker operations. of the oil estimated
by the National Academy of Sciences to be discharged from tankers at sea or at
terminals, only 16% was spilled during accidents, while 84% was spilled during
careless terminal operations or the deliberate discharge of oiled ballast water. 17J
Major tanker spills usually result from accidents --* collisions, rammings,
groundings, fires, or explosions. The two major spills of petroleum products in
California waters were the 1971 collision between the tankers Oregon Standard
and Arizona Standard in the entrance to.San Francisco Bay and the 1976 Sansinena
explosion in Los Angeles Harbor. Each resulted in spills of about 20,000 barrels
of Bunker C oil.

Vessels other than bulk'oil carriers contribute frequent small-volume spills.
In Coast Guard District 11 during 1973-1975, such vessels accounted for 29% of
the reported spills with known sources, but for only 3% of the total volume of
oil spilled during that time period (see Table 3). These spills usually involve
petroleum products rather than crude oil.

391

TABLE 5:
TANKER SPILLS VS. TANKER ARRIVALS AND VOLUME TRANSFERRED,
SOUTHERN-CALIFORNIA, 1973-1975 16/

Percent of Annual
Average West Coast Percent of Annual
Volume of Crude Oil Average West Percent of
00L Petroleum Product Coast Tanker 1975
Handled at Ports Arrivals West Coast
Port or Terminal (1973-1975) (1973-1975) Tanker Spills

Los Angel 'es Harbor 17.2% 16.7% 18.5%
Long Beach Harbor 14.9% 10.2% 11.3%
El Segundo/
Santa Monica Bay Terminals 7.5% 6.2% 2.0%
Ventura Harbor 1.5% 1.9% 0
Encina Terminal 1.1% 0.8% 0
Port Hueneme 1.0% 1.2% 1.0%
San Diego 0 . 6 0/0' 1.1% 1.0%
Carpi nteri a/
Santa Barbara Area Terminals 0.4% 0.7% 1.0%
Huntington Beach 0.2% 0.2% 0

TRANSFER OPERATIONS

Transfers may be conducted between production platform and vessel (as Exxon
intends to do with its initial Santa Ynez Unit production), between vessel and
vessel (as do Chevron and Shell near San Clemente Island by.lighterinq mid-East
crude from very large crude carriers, VLCCs, to small tankers capable of enter-
ing California ports), or between vessels and terminals (as performed at 21
marine terminals in southern California). Oil spills may occur during any of
these transfer operations.

NATURAL SEEPS

Natural seeps are a source of chronic small-volume spillage in southern
California waters, especially in the Santa Barbara Channel where more than
2,000 seeps have been identified. Estimates of seepage rates in the entire
Channel range from 40 to 670 barrels per day. 19/ Surveys conducted in 1958
and 1960 reported more than 100 pounds oil/1,000 square feet on some Channel
beaches. Similar surveys conducted in 1974-1976 found less than 10 pounds
oil/1,000 square feet at most sites. One study of historic seepage data has con-
cluded that the areal extent of active seeps in the Channel is 20% smaller in
1976 than it was in 1946.- While much remains to be learned about natural seep
phenomena, these examples suggest that natural seepage activity in the Channel
has declined in recent years. 20/

Seepage activity in the Channel may be influenced by offshore production
activity, but existing evidence is inconclusive. It may be that the reduction
in reservoir pressures caused by oil production is reducing seepage rates. This
seems to be the case at Union's Platform A, where seepage rates rose sharply when
production wells were suspended at the time of the December, 1969 spill. 21/

392

On the other hand, Union's drilling practices led to the formation of several of
the existing Platform A seeps in the first place. Further, it has been suggested
that some of the "natural" seeps in the Channel are actually oil wells which were
not properly abandoned.. 22/. The State Lands Division is.conducting research-on
natural seeps@ and the-po-tential relationships between seepage rates and offshore
oil operations,, and will submit its findings to the legislature by January 1, 1978.

F U T U R E 0 1 L S P I L L S I N S 0 U T H E R N C A L I F 0 R N I A
C 0 A S T A _LW A T E R S

Since the.Torrey Canyon and Santa Barbara Channel oil spills i-n the late
1960s, both the oi.1 industry and the U.S. Geological Survey have-taken steps to
prevent or reduce oil spillage. Although reliable statistics are not available
for the years preceding 1970, it is likely that fewer small-volume spills are
occurring now than was the case before 1970. In the Gulf of Mexico, for example,
USGS reports that the amount of oil spilled at production facilities in spills
of 50 barrels or less declined.'by 52% between 1971 and 1975 (Table 6).

TABLE 6:
VOLUME OF OIL SPILLED, GULF OF MEXICO OCS, 1971-1975 '23/

Total Volume Total Volume, Total Volume
Year Spill 50 BBL Spill 50 BBL All Spills

1971 1,493 1,285 2,778
1972@ 1,032 150 1,182
1973 921 22,175 23,096
1974 6b7 22,721 23,388
1975 711 266 977

.USGS-attributes this decline to-changes in,the operating philosophy of
the offshore producers, tougher USGS operating orders, and a substantial in-
crease in the USGS inspection force. Off California, there have been no
recorded spills from OCS tidelands or,production platforms or,pipelines.since
December, 1969. This suggests that effective steps can be and have been taken
to prevent the more easily prevented spills from occurring in the course of off-.
shore production operations.

Through technological advances, improved operating procedures.,.and more
stringent enforcement of pollution control regulation's, it is possible to
reduce the likelihood of oil spills. 24/ Unfortunateiy, the primary causes of
oil spillage -- accident and human err-or -- cannot be eliminated. In the Gulf
of Mexico, during the 1971-1975 period when small spills were reduced by 50%,
five maJor spills (1,OOU barrels) occurred. There will probably be more major
spills there in the future.

All of the offshore oil-related.facilities or activities with spill
potential production platforms, drilling rigs, pipelines, tankers, and
terminals will increase, either in number or in volume of oil handl.ed, in
the waters off California. The scale of conflict between these-separate act-
ivities is also increasing. Drilling rigs are now operating on San.Pedro Bay

393

and Santa Barbara Channel leases within either the vessel traffic lanes them-
selves or the separation zone between traffic lanes. Two of the fields dis-
covered in the Santa Barbara Channel OCS lie under the northbound vessel lane
and the recent discovery in San Pedro Bay falls within both north and south-
bound areas. These conflicts further increase the chances of oil spillage
beyond the potential associated with each separate activity or facility.

The probability of a major spill occurring off California, or anywhere
else, at any given time from any particular source is very small,, still,
there has been one major tanker spill and one major platform spi off southern
California in the last eight years. That there have been major spills in the
past proves that major spills can occur off California. The increase in off-
shore oil-related activities with oil-spill'potential enhances the probability
that another major oil spill will occur.

In its Environmental Impact Statement on Lease Sale #35, BLM predicted
that "a major spill will ultimately occur and many minor spills will occur" as
a result of the lease sale. 25/ Considering the 56 OCS leases sold in
Lease Sale #35, the 65 actiie--leases in the Santa Barbara Channel OCS, the
200,000 B/D oil now produced off southern California, the 400,000 B/D foreign
crude oil now delivered to southern California toqether with the prospect of
additional crude oil from Alaska, Elk Hills, and oroposed Lease Sale #48, we
believe that at least one major oil spill and numerous minor spills are likely
to occur off California in the future.

FATE OF SPILLED OIL IN THE MARINE ENVIRONMENT.

Spilled oil undergoes various transformations, some physical, some
chemical, and some biological, when it enters the marine environment. Of
these several kinds of transfer, briefly considered in this section, the most
important is the movement of the spilled oil through the action of wind and
water currents. This movement is also of most significance in terms of human
response, and is therefore considered in greater detail in the following section,
Trajectories.

Most crude oils and petroleum products have a lower specific gravity than
sea water and will therefore float when spilled onto water. Spilled oil spreads
out after release, and an oil slick will increase in size Until the spreading
and retarding forces acting on the oil are in equilibrium. If left alone, the
original slick is liKely to separate after several days into discrete patches
of oil several millimeters thick surrounded by larger areas covered by thinner
film of oil.

Oil slicks move readily under the infiuence of winds and water currents.
In the absence of water currents, a slick will move generally downwind at about
3.5% of the wind speed. If winds and water currents are both present, slick
movement can be estimated by 'combining the water current vector (direction and
speed) and wind vector (direction and 3.5% of speed).
Immediately after a spill occurs, natural forces begin to transfer oil
from the surface slick into all components of marine environment the atmo-

394

sphere, water column, sediments, and inhabitants.(Figure 1). Evaporatio6, wind-
generated sea spray, and bubbles bursting through the slick all act to transfer
oil into the atmosphere. It has been estimated that evaporation can remove as
much as 50% of the hydrocarbons over the lifetime of an "average" crude oil
SliCK. 26/ The volatility and solubility of petroleum hydrocarbons are both
inversei7y iroportional to molecular weight, so that evaporation and dissolution
pri'marily affect the liqhter hydrocarbons. 27/

Oil is also removed from the water surface by adsorption and absorption
onto non-buoyant particles, such as silts, clays, and organic debris. For
example, a severe rainstorm occurred shortly after the start of the 1969 Santa
Ba'rbara Channel blowout. The heavy runoff caused by this rain carried unusually
large amounts of suspended sediments into the Channel, which in turn carried
substantial quantities of the spilled oil with them into the Channel sediments.
Within four months after its onset, oil from the blowout was found to be present
in sediments throughout much of the Channel.-28/ Once in the sediments,
petroleum hydrocarbons can persist for years. 29/ Finally, wind and wave forces
may drive floating oil into either of two kinds-of emulsions: water-in-oil (like
butter) or oil-in-water (like milk). Water-in-oil emulsions are more viscous,
less readily dispersed, and slower to be degraded than oil-in-water emulsions.

Microbial organisms beg4:n to degrade oil 'as soon as it is soilled, but the
rates of degradation for different petroleum fractions vary widely. 1.0/ The petro-
leum fractions most readily attacked by bacteria -- paraffins and alkanes -- are
also the least toxic. The highly toxic aromatics are attacked much more slowly. 31/
Larger organisms take up petroleum hydrocarbons through respiratorIv or digestive
surfaces. Once inside the organism, petroleum hydrocarbons may be metabolized,
stored unaltered in tissue, or eliminated without substantial modification. When
placed in unpolluted sea water, some organisms can cleanse themselves of many,
but not all, petroleum hydrocarbons. Petroleum hydrocarbons do not appear to
increase in,concentration at successively higher levels of the food web. 31a/

OIL SPILL' TRAJECTORIES
Oil spill trajectory analyses serve two useful purposes. In terms of risk
analysis, they provide better advance knowledge of the ootential consequences
of offshore development proposals, ocs leasing decisions, the siting of new
marine oil terminals, etc. For existing offshore activities with oil spill
potential -- production platforms, offshore storage-and transfer facilities,
etc. -- such analyses assist contingency planning and the positioning of
cleanup equipment to permit faster response and to provide better protection
for threatened shoreline areas.

An oil spill trajectory model is simply a mathematical formula which
expresses the separate contributions of wind and water currents to the movement
of an oil slick. To simulate or predict oil spill trajectories in a given area,
one selects.representative wind and water current velocities and directions from
data available fo *r the study area, chooses initial spill sites, and then moves
the slick around according to the formula and the wind and water.current values
used. With the assistance of a computer, it is possible to simulate hundreds
of trajectories from a given spill site in a brief time. In theory, if not
always in practice,-such repetition helps identify the range of possible tra-
jectories -- and thus the coastal areas at risk -- and permits an estimate of
possible trajectories -- and thus the coastal areas at risk -- and permits an
estimate of the probability of a slick following any given path or coming ashore
at any given location.
395

ATMOSPHERIC
OXIDATION

WIND
SPRAY ATMOSPHERE

BURSTING
BUBBLES EVAPORATION. RAIN AND
FALLOUT

SEA SURFACE OIL SLICK SPREADING
:N
X
/Z
P ftlftw_

OIL-IN-WATER
EMULSION DISSOLUTION
Npp@_ BUBBLE-
TRANSPORT

NONBUOYANT CONVECTION
01.L RESIDUES OCEAN AND UPWELLING

,MIXING AND
SINKING
CIRCULATIONS

BIOLOGICAL
ASSIMILATION
ABSORPTION ON
NONBUOYANT
PARTICLES

SEA FL OR SIEDIMENTS*

Figural: NATURAL FORCES WHICH- DISPERSE AND DEGRADE OIL SLICKS ON WATER
Source: William D. Garrott, "Impect of Petroleum Spills on the Chemical and Physical of the Air-Sea Interface,"
Santa Barbers Oil SyrYN)osium: Offshore Petroleum Production, An Environmental Inquiry,
December, 1970, p. 91.

396

It is important to recognize both the st'rengths and the weaknesses of
these trajectory studies. The,forces and processes influencing slick movement
are complex, variable, and not entirely understood. To conduct a spill tra-
jectory model which completely and accurately characterizes all these variables
defies current data and methodology. Of necessity, therefore all models in-
corporate a series of simplifying assumptions. There is dang;r of oversimpli-
fication. If we assume the direction and velocity of wind and water currents
to be constant and uniform in time and space throughout a study area, it
is relatively easy to'predict spill trajectories. But in the southern Califor-
nia OCS, as in most areas, wind and water currents are neither constant nor
uniform, and trajectories predicated on such an assumption will be of little
value. Thus every spill trajector's model incorporates a different and highly
localized set of simplifying assumptions. Its predictive value depends on three
main factors: the mathematical formula selected to characterize wind and water
contributions to slick movement, the quality and format of the wind and water
current data available for the study area, and the degree of the sophistication
with which the two are combined.

T H E W I N D F A C T 0 R

In addition to the wind's direct effect on surface water movement ("wind
drift"), wind also drives surface waves, inducing a current movement ("Stokes
drift") separate from and perhaps-additive to the wi-nd drift, 32/ A third kind
of wind-induced surface water movement, a "leeway effect," has-Feen proposed, 33/
and others may well be found. The exact processes through which wind-induced
forces move an oil slick are not presently known.

The varied contributions of surface winds to the movement of a floating oil
slick have been studied theoretically, experimentally, and through field
observations.. The results of these studies are not in close agreement. 34/
Because the "correct" overall wind factor is not precisely known, most trajectory
models assume the wind factor to be a constant percentage of the wind speed,
usually between 3% and 4%. For example, if the wind factor is assumed to be a
constant 3%, and there are no water currents to consider, a 10-knot breeze would
push an oil slick downwind at 0.3 knots. 35/

In theory, Coriolis forces arising from the earth's rotation should
deflect slicks away from straight downwind, to the right of the Northern
Hemisphere, to the left in the Southern Hemisphere. As with the wind drift
factor, theoretical, experimental, and field results do not agree on the extent
of Coriolis deflection. 36/ Many spill trajectory models assume a 00 Coriolis
deflection angle -- that7s, no Coriolis deflection while others use 150 or
200.

T H E W A T E R C U R R E N T F A C T 0 R

It is commonly assumed that the component of a slick's movement caused by
water currents (other than those induced by Winds) equals the water current vec-
tor: that is, in the absence of winds an oil slick will move at the same-speed
and in the same direction as the water on the surface of which the slick floats.
Difficulties arise in determining which water currents the model should include.
One can choose from permanent (geostrophic) currents, tidal currents, longshore
currents, Kelvin shelf waves, shelf eddies, inertial currents, and others. 37/
As a practical matter, it is not possible to construct a model and secure dTta

397

to reflect the separate contribution of each of these kinds of movement. With
the exception of permanent (geostrophic) currents, most of these phenomena are
short-lived (minutes or hours) relative to the lifetime of a slick (days or
weeks). 38/ Further, the,net movement of surface water by these ephemeral actions
is usuaTTy small. Therefore, most models include only a single vector for water
current movement, and values ch,osen are generally considered to represent the
long-term or geostrophic currents operating in the study area.. While tidal
currents will be important in harbors or other confined waters or near shore,
their influence is probably negligible in most of the southern California
OCS. 39/

W I N D S A N D W A T E R C U R R E N T S 0 F F
S 0 U T H E R K C A L I F 0 R N I A

The major winds and water currents operating in the Southern California OCS
are powered by phenomena operating far offshore in the open Pacific. Seaward of
a line drawn southeast from Point Arguello, the winds and water currents gen-
erally reflect undisturbed, open-ocean conditions and, as such, are relatively
constant and predictable. 40/ The summer winds, originating in the semi-
permanent East Pacific High Pressure area, usually flow from the northwest at
speeds up to 15 knots (Figure 2). In winter, as theEast Pacific High moves
south, the winds weaken and become more erratic, though still generally coming
from the west quadrant. The California current moves to the southeast through-
out the year at speeds ranging from 0.25 to 0.75 knots. 41/

Within the Southern California Bight, local and regional forces come into
play, complicating wind and water current patterns. The configuration of
southern California Bight and the array of coastal mountains splinter the oceanic
northwest winds entering the Bight into weaker and more erratic breezes, with
considerable local variation (See Figure 3).

The daily land-breeze/sea-breeze cycle, driven by the differential heating
and cooling of ocean and land during every 24-hour period, influences wind
patterns in a belt along the coast extending at least 50 miles to sea. (Figure
4). j2/ Much of the Santa Barbara Channel is in the wind shadow of the Santa
Ynez and Topa Mountains, while each island creates local anomalies in the over-
all wind patterns. Santa Ana winds (steady offshore breezes of several day's
duration) occur periodically along the southern California coast.

Seaward of the Santa Rosa- Cortes Ridge, the southeast-moving California
Current is a permanent feature. Near the Tanner and Cortes Banks, the Califor-
nia Current swings to the east. Before reaching the mainland it splits, one
fork moving back into the southern California OCS, known as the Davidson Currents,
and the other continuing south along Baja California. This northern fork flows
through the southern'Channel Islands as a norithwest-moving counter-current during
the summer, fall, and winter. In the spring, this counter-current disappears. 13/
Between the southern Channel Islands and the mainland, the surface currents are
complex and variable. Figure 5 illustrates this overall current pattern. There
is no consensus as to the surface currents operating in this portion of the
southern California OCS. Some postulate a continuation of the northwest counter-
current; others postulate a return to southeast currents; and still others postu-
late the northwest flow offshore with southeast eddy currents nearer shore.
Upwelling of deep water to the surface, which creates offshore currents, occurs
periodically in some parts of the southern California OCS.

398

Figure 2: ANNUAL AVERAGE WINDS IN THE SOUTHERN CALIFORNIA BIGHT.

BARBARA

- - - - - - Iso-Velocity (Knots)
10'.
12-%., - % Wind Stream Line
14

LOS ANGELES

14
Nb

30
8 SAN
-.:-.l:)IEGO
N Miles

Source-. State Water Quality Control Board, Publication No. 27.
Survey of the Southern California Mainland Shelf, 1965.

399

Figure4 DAILY ONSHORE. BREEZE-OFFSHORE BREEZE CYCLE, SOUTHERN CALIFORNIA BIdHT.

4 ot*. 0. 40
N Wes
STREAMLINE CHART FOR JANUARY, 0000-0700 PST

N wes
STREAMLINE CHART FOR JANUARY, 1200-1700 PST

400

Type 1 Type 4
SANTA BARBARA
SANTA BARBARA

LOS ANGELES LOS ANGELES

SAN
DIEGO

Type 2 Type 5
SANTA BARBARA SANTA.BARBARA

LOS ANGELES 'D 'OS ANGELES

SAN SAN
DIEGO DI EGO

Type 3 Type 6
SANTA BARBARA
SANTA BAR SARA

LOS ANGELES
%OS ANGELES

50
*0
N Mies SAN SAN
DIEG@O $EGO
Fipbre 3: SIX COMRWN VWND PATTERNS IN THE SOUTH ERN -CALIFORNIA MGHT.
Source: State Water -Pollution Control Board. Oceanographic Survey. of the Continental Shelf of Southern California, Publication
No. 20, 1959, pp. 24 .26.

.401

Figure 5: GENERALIZED PATTERN OF SURFACE CURRENTS OFF SOUTHERN CALIFORNIA.

CQNCEPTION

07 U-S:.
06 \4 e, E-0---
MEXI
00

7
"@4

100
0

N Kilometers

Source: United States Department of the Interior, Geological Survey. Final Environmental Statement Oil and Gas Development
in the Santa Barbara Channel Outer Continental Shelf of California, Figure 11 19, 1976.
Figuystill: GENERALIZED PATTERN OF SURFACE CURRENTS, SANTA BARBARA CHANNEL.

po' nt
tonc.pl,on SANTA BARBARA
....................

Ventura

Oxnard

SAN MIGUEL ISLAND
CRUz
ANACAPA ISLAND
ROSA I . -%-
k0010
0

N Koomtws
Source: Ronald L. Kolpack, "Relationship of Migration of Natural Seep Material to Oceanography of Santa Barbara Channel."
unpublished report, August 1976.

402

It is clear that winds'and water currents in the southern California OCS are
complex, with considerable variation. With the assistance of a computer, though,
it is possible to construct a spill trajectory model which captures this variation
sufficiently to produce useful spill trajectory predictions. The limiting factor
'in the southern California OCS is not the models themselves, but the wind and
Water current data available for use in such models.
W I.. N D A N D W A T E R C U R R E N T D A T A S 0 U R C E S

The Navy maintains an archive of wind measurements taken by ships in the
southern California OCS. 44/ These are available as monthly or annual wind sum-
maries for one-degree quaU-rancles. These summaries provide helpful information
on the variability of winds from one location to another, but they do not capture
the variability of wind speed and direction at the same location over time. More-
over, these data are probably biased by mariners' natural tendency to avoid areas
of bad weather.

A wealth of long-term wind data is avai-lable from met-eorological stations and
airports along the California coast and on some of the islands. The data may be
presented as continual hourly observations or as monthly, seasonal, or annual
summaries. Anfortunately for oil spill modelling purposes, most of these stations
are either so near to topographic obstructions (Santa Barbara airport is shielded
by the.Santa Ynez Mountains, Long Beach airport by Signal Hill) or at such eleva-
tions (the Santa Catalina wind station is at 1580 feet elevation, San Nicholas at
507 feet, San Clemente at 906 feet) 45/ that taking their data as representative
of the winds at the ocean surface is-a doubtful proposition.

The southern California OCS has been studied as thoroughly as any ocean area
in the world. Vast amounts of oceanographic data, collected at different times,
in different areas, by a variety of methods and for a variety of purposes, are
available from public and private research organizations. The best summary of
long-term (geostroph,ic)@currents in the southern California OCS was assembled by
scientists from Scripps Institution of Oceanography as part of the California
Cooperative Fisheries Investigation (CALCOFI). 46/ However, the scale at which
these data are presented, and the geographic areas covered, impose limitations on
their utility for oil spill trajectory modelling.

For example., the CALCOFI current s-ummaries are presented at such a gross scale
that it is almost impossible to determine the local variations known to exist and
to have critical bearing on oil spill movement in-certain areas. This problem is
most acute immediately south of San Miguel and Santa Rosa Islands. Furthermore,
the CALCOFI summaries do.not include the Santa Barbara Channel (because of the scale
used). Kolpack has -described general current patterns in the Channel but admits
that more surface current information is required before local currents can be
reliably predicted 47/ (Figure 6).

In summary, enormous quantities-of data-exist.for both winds and water cur-
rents in the southern California OCS, but neither type is entirely satisfactory
for oil spill trajectory studies. The best wind data would contain continual hourly
observations from a series of stations on the water, but such data are not now
available. The CALCOFI current summaries are useful but are at such a-scale that
several important spill trajectory questions, hinging on current patterns in rela-
tively small areas, cannot be answered. A discussion of three spill trajectory
studies conducted for the southern California OCS illustrates the significance of
these shortcomings.

27-76658 403

S 0 U T H E R N C A L I F 0 R N I A 0 C S S P I L L
T R A J E'C T 0 R Y A N A L Y S E S

INTERSEA RESEARCH CORPORATION

Intersea Research Corporation analyzed oil spill trajectories in the south-
ern California OCS as part of the Western Oil and Gas Association's Environmental
Impact Assessment study for OCS Lease Sale #35, 48/ using CALCOFI monthly geo-
strophic current summaries and the Navy's archiv@d__ wind data. IRC divided the
study area into half-degree quadrangles and derived wind and surface water current
vectors (direction and velocity) for each quadrangle. The two vectors within each
quadrangle were resolved into one resultant slick drift vector, and the separate
slick drift vectors were manually integrated into oil slick trajectories for the
southern California OCS. Separate charts were prepared for January, April, July,
and October to demonstrate seasonal variation. These trajectories are illustrated
in Figure 7.

In addition, IRC undertook "reverse trajectory" studies for five ecologically
sensitive areas. This technique involved plotting backwards over time wind and
water current vectors to determine the location of potential spills that could
conceivably foul these sensitive areas. Figure 8 illustrates these reverse tra-
jectories, assuming a five-day drift for each spill during each season of the year.

DEVANNEY

The Environmental Protection Agency commissioned J. W. Devanney III to study
potential slick trajectories in the areas considered for sale in Lease Sale #35,
and published his report in July, 1975. 49/ Devanney used the same slick move-
ment formula as IRC, except that he assuFe--d.the wind drift factor to be 3.5%
instead of 3%.

For.wind data, Devanney used hourly wind measurements collected over a ten-
year period, Devanney was able to address the variability of the winds over time
at each station. After dividing the compass into eight 45-degree octants,
Devanney analyzed his data to determine for each octant (plus one category for
calm conditions) the probability that the wind would be from the same octant or
from any of the other octants three hours later. He also computed the mean wind
speed and variance for each direction and season at each station. From this
analysis, Devanney prepared wind-transition probability matrices for each of four
seasons at each of his three stations.

For current information, Devanney tested four hypotheses: zero current through-
out the southern California OCS, a constant 0.3-knot southeast current-throughout
the southern California OCS (taken as representative of the California Current), a
constant 0.2-knot northwest current throughout the southern California OCS (taken
as representative of the Davidson Current), and the July CALCOFI currents. The
results of the Devanney analysis are illustrated in Figure 9.

IRC and Devanney arrived at significantly different results. IRC concluded
that the wind contribution to slick drift was from two to five times greater than
that of the current, and that general slick drift was to the southeast at five to
20 nautical miles per day. 50/ Devanney concluded that for all of his current
hypotheses except the zero current hypothesis, the current contribution to slick
movement was consistently greater than that of the wind. 51/ The-significance of

404

this point is demonstrated by the predictions each study makes for the OCS leases
immediately south of Santa Rosa Island. IRC trajectories predict that any spill
originating in these tracts will be carried to the southeast and away from San
Miguel, Santa Rosa, and Santa Cruz Islands throughout the year. Deva.nney con-
dudes, "most of the spills which initiate immediately south of the western
Channel Islands (San Miguel, Santa Rosa, Santa Cruz) will reach the islands and
not be driven to the south under either the CALCOFI current assumption or the
zero geostrophic. current assumpti,on." 52/ These differences are illustrated in
Figure 10.

A serious flaw in the IRC study was its method for determining the wind vec-
tor in each of its one-half degree quadrangles. IRC took as its wind vector the
average speed and direction of the "dominant wind," defined by IRC as the
"primary direction mode of the compass rose" which included at least 50%*of the
observations. 53/ IRC's wind vector did not represent the average speed and
velocity of loffoof the wind observations in any one-half degree quadrangle, but
rather the average speed and direction of that 50% of the observations representing
what IRC considered to be the "dominant wind." Thus, in using this "average" wind
vector, IRC in fact overstated both the velocity and the persistence of the actual
winds. 54/ This casts some doubt on IRC's conclusion that most slicks originating
e _@@_outhern California Bight will be driven south and southeast, and
in th not come
ashore in California.

Devanney's method for computing the wind's contribution to slick movement
more closely approximates the actual winds in the study area, but the value of his
slick trajectory predictions is also limited by the data he chose to use. As
noted previously, his wind data were collected at stations either hundreds of feet
.above sea level (San Clemente, Santa Catalina) or separated from the ocean by a
large hill (Long Beach airport). Three of the four current hypotheses on which he.
based his trajectory predictions are of'dubious validity. But his fourth hypothe-
sis, using July CALCOFI currents, is reasonable, and'the trajectories he obtained
with this current hypothesis are distinctly different from those IRC calculated
(again, see Figure 10).

BUREAU OF LAND MANAGEMENT

In its final EIS for Lease Sale #35, the Bureau of Land Management attempted
to link offshore oil activities, Dotential slick movement, and vulnerable coastal
resources in a risk analysis. @55/_ The basis of this-analysis was the proximity
of the individual lease areas to coastal resources. BLM assigned "proximity
values" to each tract according to its distance from natural resources, cultural
resources, and areas of multiple-useactivities. 56/ Though the intent of this
massive effort is laudable, the results of the aniTysis are of limited value
because potential oil spill trajectories from the tracts were not addressed except
through BLM's mechanical proximity analysis.

OTHER OIL SPILL TRAJECTORY ANALYSES

Most oil-spill trajectory studies are either funded or conducted by federal
agencies, most commonly the National Oceanic and Atmospheric-Administration (NOAA),
the Coast Guard, and the Department of the Interior. Recent activities and
current plans for trajectory analysis by each of these agencies are described
below.

405

LEGEND

t OIL SPILL
SAJ
zi.
SUMMER
1'E
tp

Hilt,
!NK
F days WINTER/
1h
E,T' c"'
THREATE

CONCLUSION
X@ va i x
Critical periods for o

r .......

I I I N. "'L I

ER 4' , da

V @..@'Q' I 1 -600

-x, -
v I I
IDA

74
th
@70
CSORING
FA-L 4.... NII, TiR 30 dys 00
0- ILOMETERq 26 days to to BAHIA SAN QUINTIN
301 401 MILES CABO COLNETT
I

INFORMATION BASED ON TRAJECTORY STUDIES PERFORMED Califto
BY DAMES & MOOREI INTERSPEA RESEARCH FOR THE
WE
SjSTERN OIL AND GAS ASSOCIATION (WOGA) ENVIRONMENTAL
S,
OIL SPILL STUDIES A SMENT STUDY (1974). 0

7-7:
"Y
A-,
LEGEND

SENSITIVEPOINT

OA ANACAPA
@ SANTA B/
SANTA C@
SANTA M
PASADD@IK@
(D LAGUNA
<
1,zV
7T
@-Ny H1@
5-DAY 01

DECE
2 APRIL
3 JUNE
4 OCTOB
CONCLUSION

Waters between Ca
@
A 'A
,@-@:Santa Cruz Passag
O-@ mitigating oil spill
capability i's neede

OF 1110 120 KILOMETERS
01 20r 301'50 Q1 MILES

INFORMATION BASED ON TRAJECTORY STUDIES PERFORMED Ca
BY DAMES & MOOREIINTERSEA RESEARCH FOR THE WESTERN
OIL AND GAS ASSOCIATION (WOGA) ENVIRONMENTAL
OIL SPILL STUDIES ASSESSMENT STUDY (1974).

LEGEND

OILSPILLTR

CONCLUSION
Shorelines at risk are highly de
ocean c rrent hypothesis is cor
current orCALCOFI* current
LOS E

COFI - California Cooperative

A
4.

Wt
7 Str Cali omi Current"
1
10 15 110 120 130 150 KILOMETERS
01 51 101 201 301 01 MILES
@0
@NFORMATION BASED ON INTERPRETAT16'a-dF THE MARTINGALE REPORT Cal
DEVANNY) IN ONSHORE IMPACT OF OFFSHORE SOUTHERN CALIFORNIA OCS
OIL SPILL STUDIES SALE NO. 35 SOLOMON ET AL, 1976.

-e"t4-p

774,7,

Photo above: Vikoma Seapack being deployed by Clean Seas, Inc.

409

Figure lo
COMPARISON OF OIL SPIL
\-,I F r
PREDICTIONS BY INTERSEA
Pbrt
@5 A Husnam

Lai Arge"
4w, Swta
CFW Mwica
4024 ALAAD

D, Dav son =rw
D,_'6ailf6rn1'a;_ h-_
Zl,.Fall Seasons
34,-ZD, Calcof I
_13' Calcofl
Davidson- umme r -
7 N 7-"9% 171 1, Al
U Y-N -:::::rD, Davidson,
ntel I I N\
it i 'k
19 Fall an
A Spring
D,
Rom
D, California

4@-

@@i AIC 1i avidson

Ummer
D, Calco
fl,
/F

Fallff. Winter and Spring

D, California-
@D
RD,, Da@vldon
I t 1 7@@
L

AM _LL1
10 15 bo fib MILES
N09rH W@E 4@@
U@N" CURVE W W@ - - - -
19" 061S'@@ECT
9d from D
- - - - - - - - Kolpack (1

NOAA. BLM commissioned NOAA to conduct extensive environmental baseline
research in the Gulf of Alaska as a precursor to selling oil and gas leases in
this frontier OCS area. NOAA measured winds and ocean currents continually for
several years and developed a sophisticated numer-ical model of the Gulf of Alaska.
Based on NOAA's findings, Interior deleted 16 tracts from those offered in the
Northern Gulf of Alaska Lease Sale (OCS Lease Sale #39). Interior Secretary
Kleppe, announcing the deletion, stated:

New data very recently received from the National Oceanic
land Atmospheric Administration (NOAA) of the U.S. Depart-
ment of Commerce regarding wind and current patterns
indicates that drilling west of Kayak Island poses a higher
environmental risk than-previously estimated...On the basis
of these studies, I now consider the environmental risks
too great to lease these tracts at this time. 57/

On February 4, 1976, Governor Askew requested that Florida be designated an
"adjacent coastal state" under the Deepwater Port Act of 1974 (PL 93-627) in
connection with the Louslana Offshore Oil Port (LOOP) proposal for a deepwater
port off.Louslana. Such designation would have given Florida more control over
the federal decisions regarding the proposed deepwater ports.' Under Section
9(a)(2) of the Act, the Secretary of Transportation may confer such status -upon
a petitioning State "if he determines that there is a risk of damage to the
coastal environment of such state equal to or greater than the risk posed to a
state directly connected by pipeline to the proDosed deepwater port." Before
making this determination, the Secretary must consider NOAA recommendations.

NOAA's analysis of the situation had three components: 58/ (1) a spill size/
frequency/distribution analysis; (2) a trajectory analysis, Which together
enabled a comparison of the risk of exposure to oil spillaqe faced by Lousiana and
Florida; and, (3) an analysis of the vulnerable coastal resources of the two states
which, taken with the exposure analysis, permitted a comparison of the potential
damage risked by the two states. @8
J NOAA used in its slick movement formula a wind
factor of 3.1%, a permanent current vector derived from best available water
current data, and a Coriolis deflection angle of 150. NOAA concluded that the
risk of damage to Florida's coastal environment was from 1.3 to 7.2 times greater
than the risk to Lousiana and recommended to Transportation Secretary Coleman that
Florida be granted "adjacent coastal state" status.

In the spring of 1978, NASA will launch -"SeaSat," a satellite with special
equipment for observing and measuring oceanographic phenomena. A consortium of
California research institutions, headed by Cal Tech's Jet Propulsion Laboratory
and funded in large measure by NOAA, will collect continual wind and current data
in the southern California OCS for six weeks in 1977to verify and calibrate the
later "SeaSat" measurements.

NOAA and the Coast Guard have created four Spilled Oil Research Teams. Their
mission is to conduct field studies at the site of actual spills. By measuring
on-site winds, water currents, and actual slick movement, NOAA and the Coast Guard
hope to improve the accuracy of spill trajectory predictions. 59/

COAST GUARD. Under the National Oil and Hazardous Material Contingency Plan,
the Coast Guard coordinates all oil spill cleanup operations. In 1975, the Coast
Guard developed two spill trajectory models for possible use on the East Coast but

411

has not yet sponsored such studies for West Coast use. 60/ The Coast Guard also
has a Search and Rescue computer program, used in marine rescue operations, which
predicts the movement of distressed vessels or persons caused by currents and
winds. The possible application of this program to slick predictions is presently
under investigation.

DEPARTMENT OF THE INTERIOR. Prior to the Mid-Atlantic Lease Sale (#40), USGS
conducted an oil spill risk analysis for BLM. 61/ As NOAA did in its analysis of
Florida's petition for "adjacent coastal state@7status, USGS conducted its analysis
in three parts: the probabilities of oil spill occurrence; potential spill trajec-
tories; and,the location and vulnerability of specific natural and cultural
resources in the study area. On the strength of these analyses, USGS computed the
probabilities, for each season, of spills reaching the implicated coastal resources.

For the spill trajectory portion of its analysis, the USGS model used surface
current velocities taken from drift bottl.e studies, and wind records from seven
years of continual observations at Barnegat Liqhtship off New Jersey. With these
wind records, USGS computed, by a method similar to that used by Devanney in his
south-ern California OCS study, six-hour wind transition probability matrices for
each of the four seasons. The slick movement formula employed.a wind drift factor
of 3.4% and a Coriolis deflection angle of 200. USGS conducted a similar oil spill
risk analysis for the tracts considered for lease in the proposed South and North
Atlantic OCS Lease Sale (#42). 62/

Three southern California OCS Lease@Sales have been held to date, and 121
leases are in various stages of exploration, development, or production; but the
Interior Department has never calculated potential oil spill trajectories for these
leases. A fourth southern California OCS Lease Sale (#48) has been proposed for
the spring of 1978. BLM's Pacific OCS office has stated that a spill trajectory
analysis comparable to those done by USGS for the Atlantic OCS Lease Sales will'be
undertaken jointly by BLM and USGS as part of the EIS for the proposed sale. 63/
Such a trajectory analysis would be of immediate value in contingency planninTfor
spills from the existing 121 leases, as well as in identifying potential impacts
arising from Lease Sale #48.

P 0 T E N T I A L S 0 U T H E R N C A L I F 0 R N I A
b t s s P I L L T R A J E C T 0 R I F-S

To illustrate potential trajectories for spills from California OCS leases,
we have selected eight offshore locations broadly representing the geographic
distribution of existing leases. For each site, we have attempted to identify the
wind and current factors likely to control or influence oil slick movement, poten-
tial trajectories for spills originating at each site, and the shoreline areas
potentially threatened by spills from the sites. Figure 11 shows the location of
the eight potential spill sites, our trajectory conclusions, and the relatively
threatened shorelines. Conditions at each spill site are described below.

SITE 1: SAN PEDRO BAY

Winds are-usually from the west quadrant (i.e., blowing towards shore).
Currents are complex but generally parallel to shore. Hence, slicks would most
likely come ashore, with a time-to-shore of hours or days. The shoreline at risk
extends from Point Fermin to San Diego, with the most threatened area from San

412

itan
Figure
POTENTIAL 01
ra
< TRAJECTO

Port

P, Santa Los Angola--
S44,4 Monica
me
mme

hattan

Hunt' on

Is. I

TN
4@:b

(A.)

IN I I
@b
IZN@

- - - - - - - - - -
A,.0 IM FC s
011% Im In MILES

Pedro to Laguna Beach. Santa Ana winds-or seasonal upwelling could increase
time-to-shore.

SITE 2: TANNER BANKS

The California Current and westerly winds will push most slicks to south or
east. The mainland shoreline is not severely threatened because time-to-shore
might be weeks or months. All of San Clemente Island is threatened, with time-to-
shore on @`H_eorder of days or weeks, especially in the summer.

SITE 3: SANTA BARBARA ISLAND

Winds here are generally from the west quadrant. Currents are complex but
often northwest (summer, fall, winter) or southeast (spring). All of Santa
Barbara Island is threatened, with a time-to-shore of hours or days. The mainland
shoreline is less threatened, because the time-to-shore would likely be days or
weeks.

SITE 4: SANTA ROSA CORTES NORTH

This is a transition area between the southeast-moving California Current to
the west and the northwest-moving countercurrent to the east. Currents and winds
are complex, and slick trajectories are difficult to predict. Devanney predicts
slick movement toward the islands; Intersea Research Corporation predicts slick
movement away from the islands. If slicks move toward San Miguel, Santa Cruz,
and Santa Rosa, time-to-shore wouT-d be hours or days.

SITE 5: HUENEME/SANTA CLARA

The daily land-breeze/sea-breeze cycle will strongly influence slick movement.
Slicks would likely come ashore in Ventura County between Rincon Point and Point
Dume, with a time-to-shore of hours or days. Slicks could also move toward
Anacapa Island.

SITE 6: DOS CUADRAS/CARPINTERIA/PITAS POINT

The 1969 blowout originated in the Dos Cuadras field. Again, the daily land-
breeze/sea-breeze cycle will strongly influence slick movement. The shoreline
most threatened would be from Goleta Point to Port Hueneme, with a time-to-shore
of hours or days. As happened during the blowout, however, oil could come ashore
any-where in the Channel, either on the mainland or on any of the islands.

SITE 7: SANTA YNEZ

The shoreline most threatened would be from Gaviota to Goleta Point, with a
time-to-shore of hours or days. During weak winds, currents could push slicks
cross-Channel onto Richardson Rock, Wilson Rock, and San Miguel Island.

SITE 8: SAN MIGUEL/SOUTHWEST CHANNEL

Winds and currents throughout the year would push slicks onto San Miguel and
Santa Rosa Islands, with a time-to-shore of hours or days.

414

THE EFFECTS OF A SPILL

B 1 0 L 0 G I C A L E F F E C T S
The biological effects of spilled oil are the subject of considerable contro-
versy, with a literature that is voluminous, often equivocal, and occasionally
contradictory. Essential issues are hotly disputed, and general consensus does
not exist among scientists who have conducted research onthe subject. The weight
of scientific evidence available today leaves little doubt that petroleum hydro-
carbons can cause damage -- short-term, long-term, lethal, or sublethal -- to
coastal and marine organisms. What will be the precise effects of any given oil
spill is another question entirely.

Most petroleum hydrocarbons are toxic and can kill coastal and marine orga-
nisms either chemically or physically. 64/ Chemically, death may occur as a
result of poisoning,* either through diri-ct contact or ingestion (e.g., scallops,
crabs, lobsters). Physically, death may occur through coating and smothering of
intertidal organisms (e.g., barnacles, limpets) or through disruption of the body
insulation of warm-blooded animals (e.g., diving birds). 65/

Petroleum hydrocarbons can also have sublethal or indirectly lethal effects,
suc.h as the destruction or reduction of a species' food supply, reduction of repro-
duction success, and synergistic effects which may reduce resistance to other
stresses. Feeding, reproducing, and other behavioral activities of many marine
species are triggered by the presence of chemical compounds in concentrations as
low as one part per billion. Petroleum hydrocarbons, even at exceedingly low
concentrations, can mask or mimic these chemicals, thereby disrupting biological
processes dependent on such chemical signals. 66/

Spilled oil can have acute (short-term) or chronic (long-term) biological
effects. The immediate and visible effects of oil spills often receive the most
attention and publicity, but many ecoloqists believe'that the subtle and less
immediate obvious effects of spilled oii pose a larger potential threat to the
long-term health and productivity of coastal and marine populations, communities,
and ecosystems. 67/ One reviewer has separated the biological effects of spills
into three categories:

First-order effects include the direct effect of petroleum
products on the biota. These effects may be toxic; physical,
such as suffocation; or physiological, such*as internal
disturbances following ingestion. All of these may result
in immediate mortality, torpidity, or poor health. These are
generally short-term effects which usually affect all species
to some degree and show up within hours or days;

Second-order effects include changes in populations of each
species with respect to size-frequency and age structure,
productivity, standing crop, reproductive abilities, etc.
These are generally intermediate-term effects which show up
in weeks, months, and for some long-lived species, years; and

415

Third-order effects include changes at the community or eco-
system level with respect to relationships within or between
trophic levels, species composition and/or abundance, and
other aspects of community dynamics. These changes are often
the result of subtle, sublethal effects which may not show up
for months or years. 68/

FACTORS INFLUENCING THE EFFECTS OF SPILLED OIL

With the exception of sea birds, which are consistently reported to be killed
in substantial numbers, the observed effects of oil spills vary widely, ranging
from negligible 69/ to catastrophic. 70/ Some of the factors influencing the
extent of damage caused by any given spill,are the dosage of oil, the type of oil,
local weather conditions, the location of the spill, the time of year, the methods
used for cleanup, and the area's previous exposure to oil.

DOSAGE OF OIL. Toxic effects increase at higher concentrations of petroleum
hydrocarbons. Most-species have finite tolerances for oil and exhibit avoidance
behavior (if mobile), sublethal effects such as narcosis or cell damage, and
finally death as higher concentrations of petroleum hydrocarbons are reached. ZY High
concentrations can result from small spills as well as from large if winds, waves,
and currents push the spilled oil into a confined area, such as an embayment or
cove.

TYPE OF OIL. No two crude oils are the same, and each contains thousands of
compounds, primarily hydrocarbons. Because the proportion of hydrocarbons in crude
oils varies from field to field, and even from formation to formation within a
field, their overall toxicity varies as well. -The same thing is true of the
different hydrocarbon fractions. Aromatic hydrocarbons -- such as benzene, toluene,
xylene, and napthalene -- are thought to be the most immediately poisonous frac-
tion. 721 Refined oils often contain a higher percentage of aromatics than-crude
oils aii-d are usually considered to pose a greater threat to exposed organisms.

The relative toxicity of refined and crude oils is a subject of especially
fierce controversy. It has been argued that crude oils are so much less toxic than
refined oils that the two should be treated as entirely different substances. In
support of this argument, some have asserted that no crude oil spill has ever been
demonstrated to cause significant or lasting biological damage.

It is true, as noted above, that crude oils generally contain lower concentra-
tions of aromatic hydrocarbons than refined oils, and thus should have lesser toxic
potential. Table 8 compares the characteristics of four California offshore crude
oils as reported by Exxon. 73/ Aromatics are present in each of these crudes,
though constituting only 24@/Z_ by volume of the total crude. In contrast, the #2
fuel oil which caused much damage in the West Falmouth spill contained about 41%
aromatics. 74/ On the other hand, Blumer has cited published analyses of Califor-
nia crude oils which state that the aromatic content of the environmentally most
stable fraction (characterized by Blumer as boiling above 3250C.) ranges between
50-60% in Los Angeles basin crudes, and.45-49% in.Ventura.basin crudes. 75/ Thus,
California crude oils do contain aromatics, and though they constitute oTly a small
percentage of the total crude in comparison with the percentage in many refined
products, aromatics appear to be present in substantial quantities in the crude oil
fraction most resistant to evaporation, dissolution, or other weathering. There-
fore, the difference in toxic potential between crude and refined oils appears
to be of degree, rather than kind.

416

In keeping with this difference in degree, product spills are more often
observed to cause extensive biological damage than crude oil spills.

TABLE 8:
COMPARISON OF PROPERTIES OF SANTA YNEZ CRUDE OIL WITH
OTHER SANTA BARBARA CHANNEL AND CALIFORNIA CRUDE OILS

EXXON EAST
SANTA-YNEZ UNIT DOS CUADRAS CARPINTERIA WILMINGTON
TOTAL CRUDE
Gravity, uAPI 18.1 27 28.8 19
Sulfur, Wt. % 4.89 1.13 1.32 1.5
Visc. @ 1000F, SSU 1316 81 68 533
LIGHT-NAPTHA (C5-1750F)
Yield, Vol. % 3.2 4 5.2 3
RON Clear 58.5 77.9 73.2 80.3
HEAVY NAPTHA (175-3750F)
Yield, Vol. % 10.6 17.6 20.8 8.7
KEROSENE/Jet (375-5300F)
Yield, Vol..% 10.6 14.3 13.7 12.8
Aromatics, Vol. %
of Kerosene/Jet 38.3 28.7 14.8 29.1
Aromatics, Vol. %
of Total Crude 4.05 4.1 2.02 3.72
LIGHT GAS OIL/DIESEL (530-6500F) -
Yield, Vol. % 9.1 11.7 10.1 12.3
GAS OIL (650-10500F)
Yield, Vol. % 29.2 34.2 29.7 35.9
RESIDUUM (10500F+)
Yield, Vol. % 36.5 16.3 19.4 26.9
Sulfur, Wt. % 7.62 2.25 2.62 2.34

Dr. Dale Straughan, who led the team of scientists studying the effects.of the
Santa Barbara Channel blowout, has also participated in a study of the Metula crude
oil spill in.the Straits of Magellan. She has concluded that the Santa Barbara
spill did not cause significant damage, but that the Metula spill did, especially
in the int@_r_tidal'zone. 76/ Moreover, the Argea Prima, Chr ssi P. Goulandris, and
Ocean. Eagle and Urquiola tanker spills all-involved crude oil and were reported to
cause significant damage. 77/

LOCAL WEATHER CONDITIONS. Wind, wave, and current conditions,at the time of
a spill control the trajectory of the slick, the rateat which the oil is dispersed
and degraded, and the success or failure of containment and removal operations,
each of which in turn influences the effects of a spill. The winds and currents
during the first days of the Santa Barbara blowout 'Were such that significant quan-
tities of oil did not come ashore until five days after the blowout began. 78/ The
lag permitted more of the oil to be removed from the surface slick through evapora-
tion and solution than would have been-the case under different wind and current

417

conditions. Also, a severe storm occurred in the Channel a week after the blowout
began, crippling containment operations and increasing the amountbf oil ultimately
reaching the beaches. 79/ The tidal range in an area where oil comes ashore,
together with surf coni-f-tions during the time the oil is on the shore, will influ-
ence the size of the coastal area actually oiled by.the slick. Water and air
temperatures will influence the behavior of the oil as well as the rates'at which
microbial degradation of the oil proceeds. As a general rule, metabolic rates
double for every 100C increase in ambient temperature. Hence, all other factors
being equal, the higher the ambient temperature, the faster microbial organisms
will attack the spilled oil.

LOCATION OF THE SPILL. Spills occurring far offshore are less likely to come
ashore, will undergo more weathering and dispersion before reaching the coast, and
provide more time to undertake containment and removal operations than do spills
occurring close to shore. The configuration and nature of the coastal area.
threatened by a spill -- embayment, headland, open coast, harbor, rocky shore,
sandy beach, wetland, etc. -- will also influence the effects of a spill because
coastal resources vary widely in their sensitivity and vulnerability to oil spill
damage.

TIME OF YEAR. The time of year in relation to the life cycle of species
inhabiting an area is an important factor. 80/ Many larval and juvenile forms --
such as crab larvae, fish fry, or newly set-oyster spats -- are considered espe-
cially vulnerable to oil, so that a spill occurring at this stage in the life
cycle of these species would probably cause greater damage than a spill occurring
at other times of year. Similarly, if the Santa Barbara Channel blowout had
occurred when elephant seals and sea lions were nursing their pups, pup mortality
might have been considerably higher.- 81/ Again, sea bird populations fluctuate
greatly during the year, especially in wintering and breeding areas such as the
Santa Barbara Channel. Thus, the populations at risk, and hence the potential dam-
age from a spill, vary considerably depending on the time of the year.

CLEANUP METHODS. Much, though not all, of the damage caused by the Torrey
Canyon spill resulted from the indiscriminate use of dispersants which were later
found to be as toxic as the spilled oil itself. 82/ The French used chalk to.sink
about 150,000 barrels of Torrey Canyon oil in orier to prevent it from coming
ashore on the Brittany coast. 83/ No studies were conducted to determine the,
.effect of this chalk/oil mix on the benthic organisms involved, though French fish-
ermen subsequently reported fouled fishing gear and contaminated catches. 84/

PREVIOUS EXPOSURE TO OIL. The previous exposure of an area.to petroleum
hydrocarbons may influence the effects of an oil spill on that area. In the Santa
Barbara Channel, for example, natural seeps have been active for thousands of
years, increasing the background levels of petroleum hydrocarbons in Channel
waters and causing locally heavy concentrations of oil (e.g., Coal Oil Point).
Some scientists have suggested that chronic exposure to natural seep oil has
reduced species diversity at Coal Oil Point 85/ and increased the tolerance for
petroleum hydrocarbons of some of the intertf-dal species there, 86/ but the avail-
able evidence is not-conclusive. 87/

CASE STUDIES

Research on the fate and effects of spilled oil has been widely undertaken
only since the 1969 Torrey Canyon spill, and present understanding is far from

418

complete. Laboratory tests have demonstrated the toxicity of petroleum hydro-
carbons for many organisms. But laboratory environments cannot precisely dupli-
cate conditions in the field, so that extrapolation or generalization on the
basis of laboratory results is an uncertain proposition. Field experiments
invol-ving the deliberate oiling of selected areas are rarely undertaken in
the United States, though some research of this ty-pe has been conducted in other
countries. 88/

Post-spill field studies have several handicaps. When scientists study an
area where an oil spill has occurred, they generally lack.specific information
on the natural communities existing in that area prior to the spill. This compli-
cates the task of determining whether any biological or ecological changes have,.
in fact, occurred. Where such changes are.detected, it is often difficult to sort
out the effects of spilled oil from the effects of other natural and human
activities, or to establish cause-effect relationships. Even where oil spill
effects can be demonstrated, it is hard to predict the long-term results of the
spill unless surveys and analyses are repeated at regular intervals for years
after the spill.

In short, it is very difficult -to determine in the field the short-term or
long-term effects of an oil spill. In addition, the post-spill field studies
which are available are."not easily compared because of differences in study
methods and spill circumstances. Two of the most pub.licized and controversial
oil spill field studies conducted to date involve the West Falmouth oil spill and
the Santa Barbara blowout, each of which occurred in 1969. A synopsis of the
spills, the post-spill studies, and the controversial issues raised by each is
presented here to illustrate the difficulties inherent in any assessment of the
effects of spilled oil.

WEST FALMOUTH. On September 15, 1969, the barge Florida spilled 4,000
barrels of #2 fuel oil into Buzzards Bay, Massachusetts, a short distance from
the town.of West Falmouth. Over the next several days, much of the oil came
ashore in Wild Harbor Cove. Scientists'from nearby Woods Hole Oceanographic
Institute and the Marine Biological Laboratory, Woods Hole, undertook chemical
and biological studies to assess the short- and long-term effects of the spill.
Their chemical analysis established the presence and persistence of oil in the
study area; their bio1ogical surveys demonstrated the effect of the oil on resi-
dent organisms. These studies are still being carried out and will likely
continue into the fores'eeable future. It should be noted that the West Falmouth
spill study is the first in which chemical.and biological studie's have been
carried out simultaneously, in a quantitative fashion, over.extended periods of
time.

In the first hours and days after the spill, there was a massive kill affect-
ing fish, shellfish, worms, crabs, lobsters, and other crustaceans and inverte-
brates. 89/ Ben'thic (seafloor) samples collected a.week after the spill revealed
that 95%7of the organisms recovered were dead, with many of the remaining organisms
dying. Comparable destruction occurred in the tidal rivers and marshes into which
oil had been pushed by the winds and tides. West Falmouth shell'fisheries were
closed for two years, and the shellfish beds in the most heavily oiled areas remain
closed today, more than seven years later. 90/ Recolonization began about a year
after the spill, but the area has not yet recovered.its pre-spill status. Essen-
tially unmodified oil remains in the'sediments; marsh grasses are still stunted;
and bait fish and fiddler crab populations appear to be suffering long-term damage
as a result of the spill, 91/

28-76658 419

SANTA BARBARA CHANNEL BLOWOUT. Union Oil Company's fifth development well
on Platform A blew out on January 28, 1969. The blowout was brought under con-
trol ten days later, but oil still leaks from the ocean floor seeps created by
the blowout. The amount of oil discharged during the blowout is disputed. One
estimate, however, places the amount of oil released in the first 100 days after
the blowout at 77,000 barrels. 92/ Favorable winds delayed the arrival of the
oil onshore in significant quan-fiTties until four or five days after the blowout
began. Numerous studies were initiated to assess the effects of the spill,
especially in the intertidal zone. Scientists of the Allan Hancock Foundation
at the University of Southern California conducted the major study, which was
terminated in June of 1970. 93/ Barnacles, surf grass, and algae suffered signi-
ficant damage, mainly-from s-mothering by the crude oil. Thousands of sea birds
were killed. With these exceptions, the scientists were unable to demonstrate
large-scale damage to organisms in the study area. Recolonization of the oiled
intertidal areas began within a year

COMPARING THE WEST FALMOUTH AND SANTA BARBARA SPILLS

Clearly, the circumstances of each of these spills were quite different. The
West Falmouth spill involved a refined (#2 fuel) oil, comparatively high in
aromatics. In the Santa Barbara spill, the oil did not come ashore in significant
quantities until four,or five days after the spill, while at West Falmouth the oil
was ashore in a matter of hours. At West Falmouth, winds, currents, and waves
concentrated the oil into a relatively confined area, while the Santa Barbara blow-
out oil was spread along miles of open coast.

Still, the dramatic difference in observed effects of these two much-publi-
cized oil spills has aroused considerable controversy. Those who believe that oil
spills do pose a serious threat to coastal and marine life cite the West Falmouth
study, arguing that because substantial damage resulted from that spill, it could
result from any other spill, and challenge the validity of the Santa.Barbara study
on the grounds that the methods chosen to study the effects of that spill were
inadequate. On the other hand, those who believe that oil spills do not pose a
serious threat to coastal and marine life cite the Santa Barbara study, and mini-
mize the applicability of the West Falmouth study to crude oil spills on the
grounds that the West Falmouth involved a refined product. Among the major issues
in dispute are: (1) the importance of the type of oil spilled and (2) the
scientific methods chosen to study spill effects.

TYPE OF OIL SPILLED. Dr. Dale Straughan was a principal author of the USC
report on the Santa Barbara blowout. She has concluded that the major reason for
the difference in observed effects between the'two spills was the type of oil
spilled. 94/ She reasons that the Santa Barbara spill involved a crude oil which
tended to float, was relatively insoluble in water, and was comparatively low in
aromatics, while the West Falmouth spill involved a refined oil which was more
readily dispersed throughout the water column and which was comparatively high in
aromatics. This, she concludes, accounts for the fact that the primary effects
of the Santa Barbara spill were the (physical) smothering of intertidal organisms
and fouling of sea birds, while the West Falmouth spill resulted in (chemical)
poisoning of organisms throughout the study area, underwater and in the sediments
as well as at the water's edge. Some take this argument one step further and
assert that because the West Falmouth spill involved refined oil, the results of

420

the West Falmouth spill study are entirely irrelevant to the potential effects of
a crude oil spill.

Dr. Max Blumer, centrally involved in the West Falmouth spill studies, dis-
agrees with both of these lines of reasoning. He argues that fuel oil is derived
from crude oil,.that the aromatics Dresent in refined products are-also present
in crude oils, and that because aromatics are toxic when in refined oils, they
must also be toxic when in crude oil. He therefore believes that the results of
the West Falmouth spill study are applicable to crude oil spills. 95/

Dr. Blumer also challenges the argument that the difference in the oil type
accounts for the difference in observed results between the West Falmouth and
Santa Barbara spills. Woods Hole scientists analyzed samples of the oil which
came ashore after the Santa Barbara blowout and found that aromatics and other
toxic hydrocarbons were in fact present. This being the case', Blumer has con-
cluded that the difference in observed effects between the two spills was not the
result of the different type.of oil spilled, but the difference in study methods. 96/

STUDY METHODS. In the West Falmouth spill study, scientists conducted sophis-
ticated chemical analyses (gas chromatography, mass spectroscopy) of sediments and
organisms in the spill area to establish the presence and persistence of petroleum
hydrocarbons from the spilled oil. Concurrent biological examinations were con-
ducted on all organisms collected at the va-rious sampling stations. The results
of these chemical and biological studies -- conducted on a monthly basis from the
1969 spill to the present -- together constitute persuasive evidence.of the spill's
short-term and continuing long-term biological effects.

The scientists studying the effects of the Santa Barbara blowout, on the other
hand, did not make extensive use of gas chromatography or mass spectroscopy
analyses in thei-r studies and were thus unable to document the-presence, concentra-
tions, or persistence of-hydrocarbons in their sediment and organism _samples at -
the level of specificity achieved in the West Falmouth study'. Moreover, the bio-
logical survey methods used in the Santa Barbara study, especially those used on
benthic organisms, were such that not all species in the study areas were examined,
but only some species. The methods used in the Santa Barbara study have led some
scientists to question the validity of its overall conclusions. Others assert that
the design of the Santa Barbara study was such that the scientists were not in a
position to determine the actual effects of the blowout.

For example, Dr. J. H. Connell, a zoologist at the University of California
at Santa Barbara, states in a review of the USC study:

The plankton and offshore benthos (Chapters 3, 4, 5, and 9)
were sampled and reported in such a way as to make it impos-
sible to decide whether there was or was not an effect of oil...

The fauna and flora of the intertidal shore (Chapters 8 and
17), although much easier to observe, were also poorly studied.
With no observations on unpolluted or undisturbed beaches,
and using the wrong methods of sampling, without replication
or analysis, there is no possibility of a rational conclusion
being drawn concerning the effects of oil pollution...

It is clear that because standard scientific procedures were

421

not employed in most cases, there is almost no basis for
drawing any conclusions about the effects of oil. 97/

Some support for this criticism comes from the USC report itself. In discussing
his survey methods, Dr. Kristian Fauchald, author of the chapter on benthic
fauna, states:

...the survey technique in itself may not be able to show
elimination or reduction of sensitive and delicate organisms
due to oil pollution, since this technique nearly automat-
ically places the emphasis on common or large or otherwise
obvious important organisms. A study of the smaller, lesser
known organisms such as Dolychaetous annelids or amphipod
crustaceans might be of more value in estimating the effects
of pollutants in the water than a survey of the large common
organisms ... Other, more detailed techniques may have to be
applied to the problem of determining whether or not the
benthic environment has been partially or wholly destroyed
by pollutants. 98/

CONCLUSION. In a review of observed effects of the Santa Barbara blowout,
Dr. Straughan states:

...we have been unable to prove large scale damage to-plankton,
benthos, or marine mammals as a result of the oil spill in
January 1969. This does not mean that these populations
escaped completely unharmed, but it does indicate a lack of
acute catastrophic effects. (Emphasis added.) 99/

In view of the many scientists and observers who looked for spill effects in the
months following the blowout, it would have been difficult for massive short-term
damage to go unnoticed. It thus seems safe to conclude that the blowout did not
cause acute catastrophic effects. But to assert that the blowout had no long-term
effects, or that the USC study proved that no such damage resulted is to overreach
the available facts. 100/ If the USC study design had incorporated chemical
analyses and quantitative biological surveys, and if the study had continued
beyond 1970, it might have been possible to establish the actual effects of the
blowout. But because these steps were not taken, the effects of the blowout,
especially the long-term effects, remain unknown.

The West Falmouth spill study demonstrates that oil spills can cause significant,
lasting damage. The Santa Barbara blowout study demonstrates that serious short-
term damage is not an inevitable consequence of oil spillage. Beyond this, there
does not exist sufficient information to place these two spills in proper perspec-
tive, nor to judge accurately the extent of the threat posed by oil spills to
California's coastal and marine life. Every crude and refined oil is different,
every ecosystem is different, and the circumstances of every spill -- location,
size, wind and sea conditions, etc. -- are different. The reported effects of oil
spills studied in the past range from negligible to catastrophic, depending upon
the unique circumstances of each spill. As a practical matter, it is impossible
to predict with much confidence what the consequences of any future oil spills will
be. Still, the information available today demonstrates that petroleum hydrocar-
bons, whether in crude or refined oils, have, at a minimum, the potential to
cause damage short-term, long-term, lethal, sublethal to coastal and marine
life.

422

NON- B IOLOG I CAL EFFECTS

In a region such as southern California, the impact of spilled oil on the
amenity and recreational value of coastal and marine resources can be substantial,
though difficult to express in economic terms. A detailed discussion of this
matter is to.be found in the middle section of the preceding chapter. Some
insight intothe costs of spilled oil can be obtained by reviewing the after-
math of the Santa Barbara and West Falmouth spills. One estimate places the
economic cost of the Santa Barbara blowout at more than $16,000,000. 101/ A class
action suit filed by beachfront property owner@ and boat owners after the blowout
resulted in an award of $4,500,000 damages. Following the West Falmouth spill,
975 acres of shellfish beds were shut down for two years, and 60 acres remain
closed today, more than seven years after the spill. One estimate places the mar-
ket value of the clams and scallops destroyed.at $250,000. The owner of the
barge/tug responsible for the spill made an out-of-court settlement of $100,000 to
the town of Falmouth and $200,000 to the State of Massachusetts as partial compen-
sation for these and other losses resulting from the Spill. 1021

LEGAL ASPECTS

Coastal governments and residents face two key issues in the case of a spill:
1) Are legal incentives sufficient to encourage rapid and thorough cleanup; and,
2) Will victims be-adequately compensated. The short answer to these questions,
subject to the qualifications discussed below, is that adequate cleanup is,gen-
erally assured, while compensation is not.
Federal and state laws create a hodgepodge framework for preventing spills,
encouraging cleanup efforts,and compensating victims. The basic law for our pur-
pose of examining OCS-related oil spills is the Federal Water Pollution Control
Act of 1970 (FWPCA) which applies to both federal and state waters. It is useful
to examine California laws against this comprehensive backdrop because shortcomings
in the state legislation, particularly with regard to cleanup, are mostly repaired
by federal provisions that fill in the gaps. Not all gaps however are closed. 103/

S T A T E S P I L L P R E V E N T 1 0 N A N D C L E A N UJ

Various provisions of state law prohibit negligent and intentional discharges
of oil into state waters and establish,criminal or civil penalties for such action.
State law also fixes cleanup liability on spillers for negligent or intentional
spills. State law has not been interpreted to establish any sanction or impose
any liability for accidental spills unless negligence can be proved. For cleanup
liability ' this gap is more apparent than real, because the FWPCA makes spillers
liable for cleanup costs without regard to fault. For damage liability, however,
the gap is real indeed. Neither the FWPCA nor any California water pollution
control legislation imposes damage liability on non-negligent spillers. Unless
an injured party can establish the spiller's liability through some other statute,
he will have to absorb his damages without a remedy.

The state's comprehensive legislation, the Porter-Cologne Water Quality
Control Act, (Cal.Water Code, �13300 et. seg.) provides for cleanup orders and

423

civil penalties. Cleanup orders are rarely used because the provisions of the
FWPCA are used instead, and the civil penalties have been narrowly construed in
a manner which severely hampers their use.

The California Supreme Court interpreted Water Code Section 13350(a)(3) to
require the state to show proof of intent or negligence before being awarded
monetary penalties for oil spills up to $6,000 per day for each day that an actual
-discharge occurred (People v. Superior Court, S.F. 23326, 16 Cal 3d. 30, February,
1976). Since most spills occur within a relatively short period, this interpre-
tation sharply reduces the provision's effectiveness as a spill deterrent. It
also limited the provision's usefulness as a route through which the State could
seek rough compensation for the loss or damage to public resources whose actual
value is sometimes too speculative to allow recovery otherwise.

Several other code provisions also cover oil pollution. The California Fish
and Game code (Section 5650) makes it unlawful under threat of criminal penalty
to deposit or "permit to pass into ... the waters of the State" any petroleum. The
California Harbors and Navigation Code (Section 133) makes it a misdemeanor to
discharge oil from any vessel into the State's navigable waters except in case of
"unavoidable accident,, collision, or stranding." Section 151 of that code also
establishes a civil penalty of up to $6,000, in addition to full liability for
government cleanup costs, for "any person that intentionally or negligently
causes or permits any oil to be deposited in the waters of this state."

The prohibitions contained in California law may be sufficiently broad to
include spills that occur on the OCS and then migrate into the State's three-mile
jurisdiction. This study has, however, uncovered no instance where state or
local agencies have attempted to assert civil or regulatory jurisdiction over
spillers 'outside the three-mile statutory limit. For practical purposes, then,
federal law establishes the standards for regulation of oil pollution originating
within OCS waters.

F E D E R A L S P I L L P R E V E N T 1 0 N A N D C L E A N U P

The Federal Water Pollution Control Act Amendments of 1972 104/ (FWPCA)
attempts to achieve three objectives: spill prevention, spill cleanup, and assess-
ment of liability for cleanup costs. The Act does not assure compensation of
victims or posit ways to provide compensation or restoration for public resources
destroyed or damaged by a spill.

The Act deals with prevention in two ways: First, it addresses the problems
of operation and maintenance of vessels and onshore and offshore facilities by
authorizing the President to issue regulations "establishing procedures, methods,
and equipment and other requirements for equipment to prevent discharges of oil
and hazardous substances," 105/ violations of which are punishable by civil pen-
alties of up to $5,000. 1067-Second, the Act prohibits any oil discharge in
"harmful quantitiesn with violations subject to negotiable civil penalties of up
to $5,000 assessable by the Coast Guard. 107/ "Harmful quantities" is defined by
regulation as amounts sufficient to "cause a film or sheen upon or discoloration
of the surface ... or cause a sludge or emulsion to be deposited beneath the sur-
face...'.' 108/ As a practical matter, this regulatory test is met with a dis-
charge of approximately 50 gallons per square mile. 109/

The key to any spill cleanup is early mobilization of equipment before the

424

spill becomes widely dispersed.. In order to facilitate cleanup, the Act requires
the person in charge of a 'vessel or facility (including offshore platforms) from
which a discharge occures to notify the Coast Guard "immediately." 110/

The FWPCA authorizes the President to "act to remove" any oil spill "unless
he determines such removal will be done properly by the owner or operator of the.
vessel, onshore facility, or offshore.facility from which the.discharge
occurs.11 ill/ In practice, the primary reliance for cleanup is upon the
spiller. 11Y/ As a back-up, the National Contingency Plan 'provides a mechanism
for the Coast Guard to monitor these efforts to intervene directly where necessary
and to re.imburse states for the costs they incur in removing the discharge. 113/.

To encourage rapid mobilization.of cleanup efforts, the-Act also authorized.
the establishment of a revolving oil spill cleanup fund of $35 million, 114/ which
was funded at a level of $20 million, available.for financing federal and state
cleanup costs.and reimbursing spillers for their own cleanup costs where.they can
demonstrate they are not liable under the Act. The fund has dwindled to' a level
of about $1 million, reflecting the difficulty of identifying Spillers in order to
assess cleanup costs. 115/

CLEANUP LIABILITY

In.the case of-OCS "drilling or production operations," Interior Department
regulations issued under the OCS Lands Act make the lessee financially responsible
for "the control and.total removal of the pollutant, wheresoever-found," resulting
from the operations, If the lessee fails to take necessary cleanup measures, the
USGS Area Supervisor is authorized to do so at-the lessee's expense..116/ These
regulations,.promulgated immediately following the Santa Barbara blowout, establish
absolute, unlimited.liability for spill cleanup.,from any OCS lease, wherever-
located.

The FWPCA covers a broader scope of facilities, but more limited geographic
range than the OCS regulations. The FWPCA is applicable only to the bounds of
the twelve-mile contiguous zone, but within that zone it covers all vessels and
onshore and offshore facilities, except those OCS facilities under Interior Depart
ment jurisdiction. 117/ Where the FWPCA does apply,,it establishes a facility
operator's liabilit@-for actual lots,to the United States for "removal of the
oil ... from the water and shorelines for the taking of such-otker actions as may
be necessary to minimize or mitigate damage to the public health or welfare,,in-
cluding, but not limited to, fish,,shellfish, wildlife@, and public and@private -
property, shorelines and beaches-." 118/ State.cleanup efforts are reimbursable
as well, if performed pursuant to the National Contingency Plan. 119/

Liability for cleanup costs is imposed regardless of fault. It does not
depend upon proof of negligence. Liability@is limited by law to $8 mil-lion for.-
onshore-and offshore facilities and $14 million for vessels.,,.except in the-case
of "willful negligence" or "willful misconduct," in which case.the operator or
owner is fully li'able for all cleanup costs. 1201 Liabilit 'y can be.avoided only
where.it is proven the spill was solely due to: 1) an act of God; 2) an act of
war; 3)-acts of a third party;@4) negligence on the part of the U.S. Government;
or, 5) a combination of the above. 12.1/,
Several limitations should be.noted concerning the federal framework. First,
neither the F-WPCA, nor the Interior.Department regulations,include restoration or

425

restocking of damaged aquatic resources within their provisions for "control" or
"removal" of polluting oil. 122/ Second, federal statutes provide for no compen-
sation to damaged private parties. The FWPCA merely states that it does not
affect the operator's obligations to third parties. 123/ The Interior Department
regulations provide that "the lessee's liability to third parties ... shall be
,governed by applicable law," 124/ which means California common law or Federal
Admiralty law, depending on the circumstances.

FINANCING CLEANUP OPERATIONS

The Federal Water Pollution Control Act assumes that a spiller will provide
the first line of defense in containing and cleanup of oil spills. If a spiller
does not act, the Coast Guard is authorized to undertake cleanup at the spiller's
expense. The incentive for a spiller's quick response is that his own cleanup
may be less expensive than the government's. If the Coast Guard orders the clean-
up, both federal and state containment and cleanup costs are reimbursable, either
from the spiller, or from the Oil Spill Contingency Fund. The FWPCA makes no
provision for reimbursing expenditures by local governments or private parties.
These efforts are not eligible for Contingency Fund reimbursement and the Act does
not impose liability upon the spiller to reimburse them.

The only way local government and private cleanup expenditures may be recov-
ered is from the spiller. For "phantom" spills, where the identity of the spiller
is not established, there is no mechanism to reimburse these costs. When the
responsible party is known, cleanup costs must be recovered through court action,
just like damage claims. Actions to recover cleanup costs are subject to the
same hurdles: the legal process is time-consuming and expensive; and negligence
may have to be established concerning highly technical operations beyond the know-
ledge of the injured party.

C 0 M P E N S A T 1 0 N 0 F V I C T I M S

A potential plaintiff damaged by an oil spill faces numerous obstacles to
complete and adequate compensation. The first problem is how to identify the
polluter. In spectacular spi.lls like the Santa Barbara blowout in 1969, the
Torrey Canyon grounding in 1967, or the San Francisco Bay collision in 1971,
identification does not pose an insuperable difficulty. In more routine spills,
however, private plaintiffs may be left completely without remedy. Even the
Coast Guard, with its considerable legal an@ technical resources,has been thwarted
by this problem, and inability to identify and recover from polluters is the major
reason for the dramatic depletion of the "revolving" spill cleanup fund estab-
lished by the FWPCA. Coast Guard studies indicate that between 1971 and 1973,
they could identify discharges of a mere 31% of the spills involving fund expendi-
tures. Even more striking is the fact that by April, 1974, they had succeeded in
obtaining full or partial compensation from an even more meager 8% of the "known
source incidents," or somewhat less than 3% of the spills involving fund expendi-
tures. 125/ There is no reason to expect private plaintiffs to be more successful.

Where the spiller is known and where individual damage claims are not
excessive, the oil industry has a very good-record of settling claims. When the
American Petroleum Institute solicited claims-settlement data from member companies,
respondents indicated that between 1971 and 1974, 1332 of 1339 claims were settled
out of court for a total of $598,208, an average of less than $500 per claim. The
API study did not include the 1969 Santa Barbara spill, where settlement took six

426

years and where payment for legally cognizable damages exceeded $ 14 million; nor
did it attempt to sample unsatisfied potential claimants with injuries that could
not be attributed to an identified spiller, nor whose injuries were.not legally
recognized as damages by law. The.number of unsatisfied.claimants cannot be
M
recisel determined, but thq surely exist, since over.45'/O of spills off southern
ifornL from 1973-75 were ,phantom" spills where the spiller could not be
identified. T26/ -

The second problem is to establish the Polluter's liability. Depending on
whether the spill occurs from a vessel or a platform and whether the injury is to
a maritime or non-maritime interest, the applicable law for establishing liability
and damages may be either Federal.Admiralty law or California common law. 127/
Cases involving drilling accidents or marine traffic may prove difficult for indi-
vidual.plaintiffs to establish negligence on the part of the spiller since many
of the issues are complex and technical and the sequence of events is probably out-
side the knowledge of the injured party. Onshore drilling has long,been held an-
ultrahazardous activity in California so that the driller is absol'utely liable
for damages, once a plaintiff has proved the spiller was ne'gligent. 128/ In the
Santa Barbara spill, however, the defendants consistently maintained that specific
proof of negligence had to be presented. The government plaintiffs who chose to
litigate the Santa Barbara spill 'spent over one and one-half years in discovery
proceedings, which did not begin until three years after the spill. 129/

LIMITS OF DAMAGES

The thi,td major problem in adequately compensating vict "ims is that many of
the harms most feared by coastal com 'munities are not legally compensable in the
common law. 130/ Even in cases where liability is admitted, negotiations drag on
interminably before settlement, to the disadvantage of small plaintiffs.
The word "damages" is a term of art denoting a compensation or indemnity which
may be recovered in the courts by any person who has wrongly suffered injury. 131/
A definitive answer as t6whether damages are recoverable for any particular injury
in a specific case must await a court's determination.

There is general agreement that damages include costs relating to repai r or
replacement of real and personal property damaged by oil -- beaches, docks, small
boats, fishing gear, etc. Under some circumstances, inconvenience and discomfort
would be included as well. In some limited cases, claimants may recover for
consequential economic losses, such as loss of profits in the fishing or tourist
industry, and for injury to the marine environment and its living resources. The
outcome'in any particular case depends on a host of factual legal distinctions.

Generally, courts have been reluctant to permit individual recovery for
marine pollution unless a claimant can demonstrate a special injury setting
him apart from the public at large. Courts have found such special injury
in the case of commercial clamdiggers 132/ and fishermen. 133/ In one case, the
court distinguished the clamdiggers' plight from that of local businesses without
beach-front property that "claim only of a loss of customers indirectly resulting
from alleged pollution." 134/ In the fishermen's case, arising out of the 1969
Santa Barbara blowout, the court carefully warned:

...our holding in this case does not open the door to claims
that may be asserted by those other than commercial fishermen,
whose economic or personal affairs were discommoded by the oil
spill of January 28, 1969. Nothing said in this opinion is

427

intended to suggest, for example, that every decline in the
general commercial activity of every business in the Santa
Barbara area following the occurrences of 1969 constitutes a
legally cognizable injury for which the defendants may be
responsible." 135/

Claimants such as hotels, restaurants, and other small businesses depending on
tourists have generally been denied recovery for their economic losses in marine
pollution cases unless they happen.to own waterfront property which was directly
affected. Even in cases where a commercial fisherman can recover, it is not
established that employees may recover their losses as well. Courts have split
on whether crew members may recover their lost wages when a vessel is inoperable
from negligence of the owner of another vessel. T36/

The ownership of beachfront property may be a determining factor as to whe-
ther a business may recover at all, and-of the extent of damages. In addition to
claims for injuries to real or personal property, courts have generally entertained
claims from affected property owners for economic injury, such as loss of profit
or loss or impairment of earning capacity. At least one court has allowed property
owners to recover damages for intangible harm such as annoyance, inconvenience, and
discomfort beyond the rental value of the property for the time when its use was
impaired by an oil spill. 137/ Persons who were similarly annoyed, inconvenienced,
or discomforted by the fouling of a public beach, however, have no special and
particular injuries setting them sufficiently apart from the public-at-large to
establish legally cognizable damages. This was the reasoning in a case arising
from the Santa Barbara spill, where pleasure boat operators were denied recovery
for "loss of use" of their craft as a result of the spill. 138/

The ri ght of state and local governments to recover damages for loss Of pro-
prietary income, such as-fees paid by park visitors and concessionaire and lease-
hold income, is generally conceded. 139/- However, the riqht of-state and.local
governments to recover for damage to--tFe- marine environment and natural resources
has been hotly contested, as have the standards for measuring those damages. 140/
Another disputed area is the right of state and local governments to recover
damages,-loss of tax revenue from real and personal property, and business acti-
vities affected by a spill. This was claimed in the Santa Barbara spill, but the
defendants asserted there was no legal basis for such a claim. 141/ Since-a
settlement was reached, no court has ruled on the va-lidity of the tax loss.as a
damage element.

In summary, many of the injuries arising from an oil spill have no legal
remedy. Damages for intangible losses such as annoyance or inconvenience, as
might be experienced by tourists and residents, are restricted to real property
owners whose property interest-was physically.harmed.- Even with economic losses,
existing law provides damages to only a portionTof the claimants who-suffer.from
a spill. The principal claimants with no current legal avenue for relief incl-ude
the owners,of hotels, motels, trailer parks, campgrounds, restaurants, stores,.
and the like, whose businesses depend-upon the-tourist trade but who are-not
physically affected by an oil spill. They have no currentright,to recover for-
loss of profits resulting from a business decline attributable to oil polluti.on.
Similarly, their employees and even employees of businesses directly and physically
affected by oil pollution have no clear right to damages for lost wages. The
third claimant group.without legal remedy is state and local-governments that
suffer tax revenue losses-from a pollution incident. Claimants who may-or may not

428

have a legal right to recover for economic loss include charter boat operators,
diving instructors, and others whose business depends'upon the sea.

LEGISLATIVE REMEDIES

The Interior Department-has predicted that at least one major spill is a
virtual certainty from the southern California OCS areas leased in December, 1975.
For a large oil field discovery in this area, there is over a 95% chance of a
platform spill exceeding 1000 barrels during the 30-year development and produc-
tion period. For medium and small finds, the chances of such a spill were
estimated at 70% and 25% respectively. If a large platform spill does occur,
Interior estimated an 80% chance it would exceed 2380 barrels and a,35% chance it
would exceed 23,000 barrels. 142/ Other federal leases, state offshore oil opera-'
tions and tanker traffic, of course, all provide additional potential sources of
spills.

In light of this risk, it is essential that state and federal laws protect
the public and public entities from the threat of loss or harm from OCS or non-OCS
oil spills. That protection does not now exist. As indicated above, there are
several major inadequacies in the current law:

1. absolute liability is not clearly the standard for imposing liability
for damages resulting from oil spills;
2. the state and its citizens are subject to protracted and expensive
litigation to recover costs and damages resulting from some oil spills;
3. some losses resulting from oil spills are not recoverable under tradi-
tional notions of "legal damages"; and,
4. Protracted and expensive litigation is especially unfair for the indivi-
dual citizen whose claim for costs and damages amounts to only a few
thousand dollars.

In order to address these problems, oil spill liability funds have been pro-
posed at both the state and fedcral.level. The thrust of these efforts is to
create a fund to compensate damaged parties on a timely basis, without expensive
litigation and unfettered by an array of legal technicalities limiting recovery
where it is deserved. Most proposals would start and replenish the fund through
recovery from sp,illers and a small tax on oil operations. The fund thus maintains
incentives for spill prevention and internalizes spill costs upon the responsible
parties.

The California Legislature dealt with two major spill liability fund bills
(SB 387, AB 4008) in the 1975-76 Session. Both generally followed the outline
described above, but neither reached a floor vote. Two piecemeal spill fund bills
at the federal level have been enacted in conjunction with the Trans-Alaskan
Pipeline Act and the Deepwater Port Act-of 1974. The 94th Congress produced no
liability legislation, although spill fund provisions were included in both the
House and Senate versions of the OCS Amendments and were the subject of several
bills in each body. The House Merchant Marine and Fisheries Committee reported
the Comprehensive Oil Pollution Liability and Compensation Act of.1976 (HR 14862)
on September 9, 1976. The bill represented a compromise-between the three major
versions introduced, but it died late in the session without further action by
the-House.

The House bill is worth examining, however, because it contains the essential

429

elements of a workable compensation fund. The bill provided for a $200 million
fund from oil terminal fees, which would be available to claimants for cleanup
and removal costs as well as for damages. The fund would be liable, except in
the case-of war or riot or where the claimant's own gross negligence or willful
misconduct caused the loss. Spillers would in turn be strictly liable to the fund
in all cases where the fund was used, with the sole exception of cases where the
incident was caused by the act or omission of a third party. In that case, the
claimant would still be compensated, but the fund would either spread the loss
over all fee payers or proceed after the negligent third party.

The liability legislation provided recovery for some damages not generally
permitted by common law. Owners and lessors of real or personal property directly
affected by a spill were allowed to claim damages, including cleanup costs, injury
to property, and loss of use of property. Non-riparian claimants, such as hotel
owners whose property is not in direct contact with a spill but who nonetheless
might suffer business losses, would have been denied recovery by common law.
These claimants and their employees would be-allowed damages for loss of profit
or income if they derive more than 25% of their earnings from activities using
an affected property or resource. They could also claim damages.for loss of use
of the natural resource. The definition of state and local government damages
was expanded. For personal or riparian real property, government claimants could
recover damages for cleanup costs, injury to property, and loss of use of injured
property, as well as any other cleanup costs authorized under the FWPCA. In
addition, the loss of tax revenues caused by injury of real or personal property
for one year could be claimed. Finally, states (but not local governments) would
be able to recover for injury to natural resources, though the measure of damages
was not spelled out.

RECOMMENDATION

The State should support the enactment of state or federal legislation to
establish a spill liability compensation fund financed through equitable taxes on
oil operations and providing a source for private and public claimants to obtain
adequate redress for harms not now recognized as "legal damages" and without the
uncertainty and expense of protracted litigation.

OIL SPILL RESPONSE

The 1969 Santa Barbara Channel blowout caught industry and government unpre-
pared and painfully demonstrated the inadequacy of then-existing equipment and
procedures to clean up offshore oil spills. 143/ The embarrassingly large gap
between what was needed and what was available, between predicted performance of
equipment and actual field performance, triggered substantial efforts by industry
and government to devise more effective oil spill cleanup methods. Two areas of
concentration have been contingency planning to improve the speed of response,
and developing cleanup equipment capable of functioning under a wider range of
field conditions.

C 0 N T I N G E N C Y P L A N S

An oil spill is an emergency requiring immediate and coordinated action. The
most effective way to limit the damage caused by a spill is to contain and remove

430

from the water as much of the oil as possible as rapidly as possible. With many
different agencies, organizations, jurisdictions,and authorities involved in
cleanup operations, there are numerous opportunities for confusion and delay. In
order to streamline the response, oil spill contingency plans have been drawn up
by federal agencies, state agencies, local agencies, and industry organizations.
These contingency plans specify lines of authority, procedures to be followed,
and equipment available for use in responding to spills.

FEDERAL

The National Oil and Hazardous Materials Pollution Contingency Plan estab-
lishes the frame within which oil spills are cleaned up in the United States. 144/
The Coast Guard administers the plan for spills in coastal waters, the contiguous
zone, and the high seas. Through a memorandum of understanding between the
Secretaries of Transportation and Interior, the USGS has exclusive authority over
measures to control oil spills at and within 500 yards of OCS facilities. 145/

Under the plan, Coast Guard personnel investigate all reported offshore
spills, notify the party responsible (if known) of his obligation to clean up the
spill, and supervise or -- if necessary -- direct the cleanup operation. If, for
whatever reason, cleanup is not promptly begun by the responsible party, the
Coast Guard can hire the private organizations to do the work. Most spills are
cleaned up by private personnel working for either the spiller, the oil spill
cleanup cooperative in whose area the sVill occurs., or an independent cleanup
contractor. The Coa.st Guard seldom finds it-necessary to undertake the actual
cleanup itself, though it often provides communications equipment, containment
boom, and other federal resources to assist the private,cleanup operation. Regard-
less of who actually cleans up the spill, the Coast Guard retains final authority
over procedures and equipment used, and together with various federal and state
agencies, controls the use of dispersants and other chemical agents. 146/

To improve coordination among the many government agencies participating in
or monitoring spill cleanup operations, the National Plan provides for the estab-
lishment of Regional Response Teams (RRT). Within Region 9, which includes
California, Arizona, Nevada, and Hawaii, sub-Regional Response Teams (SRT) have
been formed. Primary members of the SRT for southern California include the Coast
Guard, EPA, the Departments of Defense and Interior, and California's Department
of Fish and G-ame.

STATE

California has its own oil spill contingency plan, which has been recommended
as a model state plan by the American Petroleum Institute. 147/ Under California's
plan, a State Support Team (SST) and a State Interagency Oil Spill Committee
(SIOSC) have been established to coordinate the activities of State agencies with
each other and with federal, local, and industry agencies and organizations. The
SST has designated the Director of the Department of Fish and Game as the State
Operating Authority (SOA) in charge of state activities under the plan.

Because federal law reserves ultimate authority over cleanup operations to
the Coast Guard and other federal agencies, the State's role-in offshore cleanup
operations is that of observer, assistant, and advisor -- with the important excep-
tion that the State has veto power over the use.of chemical agents in state waters.
In practice, Department of Fish and Game personnel investigate all spills in state

431

waters and many spills in federal waters, monitor, assist, and advise federal and
industry cleanup operations, and maintain liaison between local, state, federal,
and industry agencies and organizations. California does not have a fund to pay
for private'cleanup efforts and must tap the Coast Guard's revolving fund to
require the services of industry or private cleanup organizations.

LOCAL

The role of local officials during spill cleanup operations is generally
limited to monitoring and providing onshore logistical support for industry and
federal efforts, such as controlling traffic, arranging for the use of local har-
bor facilities, providing for the disposal-or recycling of recovered oil, identi-
fying coastal access point, etc. When oil comes ashore, the focus of the overall
cleanup operation shifts to the oiled shoreline areas, and local and state personnel
and equipment may be directly involved in the task of removing the oil and
restoring -- to the extent possible -- oiled areas to pre-spill condition.

State officials assist local governments to improve local knowledge and
participation in spill cleanup operations, and to develop local contingency plans.
In 1974, the Department of Fish and Game sponsored workshops in Long Beach and
Santa Barbara to acquaint local officials there with federal, state and industry
spill response procedures (see Appendix 8). The County of Los Angeles Department
of Beaches recently completed an inventory of beach access routes within Los
Angeles County as the first step in the oil spill contingency plan it is develop-
ing (see Appendix 9).

INDUSTRY

The U.S. Geological Survey requires the operators of all OCS facilities to
prepare oil spill contingency plans describing the type, ouality, and location of
spill control equipment available to the operator, and the procedures ta be
followed in the event of a spill. 148/ Similar requirements have been imposed by
various state and federal agencies on oil-related facilities within three miles
of shore. 149/

Industry has organized three oil spill cleanup cooperative associations in
southern California to respond to offshore oil spills. Clean Seas, Inc., based in
Santa Barbara, will respond to spills in state and federal waters between Ca 'pe San
Martin (north of Estero Bay) and Point Dume. Clean Coastal Waters, Inc., in Long
Beach, will respond to spills in state waters between Point Dume and the Mexican
border. The Southern California Petroleum Contingency Organization (SCPCO), also
based in Long Beach, is being established to respond to spills originating at the
leases sold in Lease Sale #35.

These cooperatives function in a straiqhtforward fashion: member Companies,
generally i,ncluding all offshore producers in the cooperative's response area as
well as other potential spillers, are assessed annual fees based on the level of
their offshore activities. These funds are used to purchase and maintain stock-
piles of co 'ntainment boom, skimming devices, workboats, chemical agents, radios,
etc., at a central location, and to train industry personnel in the'use of the
equipment. In the event of a spill, the cooperative delivers to the company or
to the spill site whatever equipment the company requests, together with laborers
provided through contractors retained by the cooperative. Cooperatives will make
their equipment and services available to non-member companies and agencies (such

432

as the Coast Guard) if the equipment is not being used by member companies at the
time.

In southern California, most containment and recovery equipment suited for
open ocean cleanup operations is stored and maintained by the cooperatives at
central locations onshore. 150/ Under existing state and federal regulations,
offshore producers keep small amounts of "first aid" spill containment and recovery
@equipment at production or drilling facilities, and rely-on the shore-based equip-
ment to deal with spills larger than five to ten barrels. For Lease Sale #35
operators, many of whose leases lie 40 to 100 miles from the mainland, the SCPCO
has stockpiled some of its equipment on Santa Catalina Island, and is trying to
develop a system to deliver and deploy containment boom by helicopter. 151/ If
this helicopter system can be made to work effectively and reliably, it will
sharply reduce response time and thus.increase'the chances for successful oil spill
cleanup.

C L E A N U P E Q U I P M E N T

State and federal policies advocate the physical removal of spilled oil
from water whenever possible. 152/ For this reason, first priority in spill clean-
up operations is always given to at-sea containment and recovery attempts. Speed
of response is critical to the success of such efforts, because: oil slicks are
thickest immediately after the spill occurs.and thus most easily contained and
removed; water-soluble toxic hydrocarbons have not yet been released from the slick
in.large quantities; and the slick has less time to spread or move toward shore. 153/

Containment booms are floating barriers which, under suitable circum-
stances, Prevent the spread or passage of an oil slick from.one side of the boom to
the other. At sea, booms are commonly used to: (1) surround an'oil slick to prevent
its further spread or movement; and, (2) help concentrate the spilled oil in order to
facilitate,recovery of the oil from the water. Along the shore, booms are often
deployed across the entrance to harbors, marinas, or estuaries to prevent slicks
from entering and fouling such areas or to steer the oil toward recovery devices. 154/

To recover spilled oil from the water, a variety of skimming devices have
been developed. One kind of'skimmer.uses weirs or near-surface intakes to pump in
fluids from the water surface or just below. Another type of skimmer uses belts of
a material that preferentially absorbes oil and repels water; the belts are con-
tinuously rotated into and out of the water, with oil from the slick squeezed off
into a holding tank while the belt continues back into the-water in an endless
cycle. For any skimmer to work at top efficiency, the spilled oil must be concen-
-trated at the skimming site.. Containment booms and sorbents -- materials that
float, absorb oil, and-repel' water --.are commonly used in conjunction with skim-
,-mers to increase recovery rates. Figure 12 is a photo of a skimmer in operation.

In addition to the response time, the success or failure of at-sea contain-
ment and recovery operations depends heavily on the environmental conditions under
which the attempt is made. Under calm ocean conditions, as shown in Figure 12,
existing.containment and recovery equipment will function effectively, and success-
ful at-sea recovery of the spilled oil is likely to be accomplished. But the
effectiveness of containment booms and skimmers falls off dramatically as ocean
conditions worsen. The booms will not perform effectively if water currents exceed
one to two knots, the exact failure point depending on the type of boom used.
Currents of sufficient velocity to hamper containment efforts are generally fou'nd

433

FIGURE 12: OIL SKIMMER OPERATION (SOURCE: CLEAN SEAS INC.)

434

only near shore, or in restricted bodies of water such as harbors, tidal basins,
or river mouths.. In open ocean cleanup operations, currents are usually of less
importance than the sea state, which is largely determined by wind and wave
conditions.

The operating limit for a containment boom is often expressed in terms of
wave height; for example, Brand X boom may be rated by its manufacturers as cap-
able of containing oil in waves up to six feet. But wave height alone is not the
determining factor, because.wave.peri.od, wave steepness, and the.amount of tur-
bulence at the ocean surface are also important. If winds are moderate, and waves
in the vicinity of the slick consist-only of smooth,.Iong-period swells, Brand X
may indeed contain oil effectively until wave height exceeds six feet. But if
local winds superimpose short-period steep-sided wind-chop on top of the swell --
as often occurs in 'the Santa Barbara Channel or San.Pedro Bay in late after.noon---
or if the waves are breaking, Brand X may cease to be effective when wave height
exceeds three feet.

The efficiency of skimming devices is similarly dependent on sea conditions.
Pump or weir type skimmers take in water as well as oil, and-the oil-water re-
-covery ratio falls off rapidly as the sea state worsens.. Endless-belt skimmers
are@designed to achieve a high oil-water ratio, but their recovery rate also drODS.
off in rougher sea states. As has been noted'elsewhere-, the most prominent
characteristic of skimming devices is the variance between predicted and actual
performance. 155/ Generally speakinq, effective.skimming is unlikely to take
place when ocean conditions are.anything-other than moderately.calm. 156/ In
addition to their effect on cleanup equipment, environmental conditio@@salso
influence the effectiveness of the people using the equipment. It is much more
difficult and hazardous.to undertake at-sea operations at night or during fogs
than it is during daylight or clear conditions.

OIL SPILL CLEANUP AGENTS

. An oil.spill cleanup agent (OSCA) is any substance.applied to oil on water
or on the shoreline in order to disperse, remove, or otherwise control the oil.157/
Any OSCA applied.in or on state waters must be licensed by the State Water -
Resources Control Board,znd the use of an OSCA is supervis ,ed and enforced by the
Department of*Fish and Gamei' Disperstng, collecting, and sinking agents have all
.been developed for.application-.-on oil slicks. Biodegradants and burning agents
are under development, but not yet considered-effective. Collecting agents in-
clude gelling and herding chemicals and sorbents, the function of which. is to
absorb, congeal, gel.or-demulsify oil, leaving an end product which remains afloat
for later collection or burning. Sinking agents: increase the specific'gravity of
floating oil to the point where it sinks through the water column to the.seafloor.
Dispersants act by altering the surface tension of the oil-, to increase the
spreading of slicks and promote the emulsification and mixing of oil into the
water column.

CHEMICAL DISPERSANTS.

During the 1967 Torrey Canyon.spi-11, large quantities of dispersants were
used. Because dispersants were heavily used@on the shoreline itself, and because
the brands used were themselves highly toxic, the biological, damage caused by the.
dispersants was found to-be at least.as great as that caused by the oil itself..158/
Since then, industry has developed more acceptable dispersants; some.recently'

29--76658 435

developed products are reputed to be 10,000 times less toxic than those used in
1967. But the use of dispersants remains the subject of considerable controversY.

Advocates argue that: (1) by increasing the surface area of an oil slick,
dispersants accelerate the rates of physical, chemical, and biological degradation
of spilledoil and lower the concentration of oil in the water; (2) by reducing
the tendency of oil droplets to adhere to each other and to solid surfaces, dis-
persants can reduce the number of birds killed; (3) dispersants are the least
expensive method of dealing with spilled oil; and,(4) by transferring oil from the
water surface into the water column, dispersants reduce the chance of oil coming
ashore in heavy concentrations, thereby reducing the potential for shoreline
damage.

Opponents argue that: (1) dispersants remain toxic -- though not as toxic as
earlier versions -- so that their use actually increases the toxic load on organ-
isms in the affected area; (2) by spreading spilled oil over a greater area,
dispersants increase the number of organisms exposed to potential damage from both
the oil and the dispersants; (3) if dispersants function effectively, they eli-
minate any chance of physically recovering the spilled oil; and,(4) by removing.
the surface appearance but not the actual presence of oil,.dispersants are merely
a cosmetic solution to oil spills.

Because dispersants have both desirable and-undesirable attributes, California
and federal authorities have adopted regulations restricting but not altogether
prohibiting their use. 159/ As noted earlier, first priority is always given to
oil from the water. But at-sea containment and
the physical removal of spi
recovery is often impossible, and situations mayarise where dispersants offer the
only chance to prevent an oil slick from coming ashore and fouling sensitive
coastal resources. Under present law, state and federal authorities have the
flexibility to permit the controlled use of dispersants if their use is likely-to
result in less overall damage than would occur if the slick were left alone.

In practice, dispersants are rarely used off California. A good example of
the circumstances under which dispersants might be considered for use,is provided
by the tanker Irene's Challenger, which broke up near Midway Island on
January 18, 1977. 160/ Vthree million gallon crude oil slick formed and, under
the winds prevailing at that time, began to move toward a Hawaiian fur seal sanc-
tuary about 40 miles away. Adequate containment and removal equipment could not
be delivered to the site in time to keep the oil away from the sanctuary. Federal
spill response team officials on the scene judged the potential threat to the
seals-to outweigh the potential threat caused by using dispersants and made pre-
parations.to apply dispersants if the slick continued to move toward the sanctuary.
By the time the slick had approached within 20 milest however, the winds shifted,
moving the slick away from the sanctuary and out in to the open ocean. Since the
threat was gone, the overriding need for dispersants no longer existed and none
was applied.

ASSESSMENT

Oil spill cleanup procedures and equipment have improved substantially since the
1969 blowout, but if a spill occurs in anything other than ideal conditions --
daylight, calm seas, near a-cooperative -- the success of at-sea containment and
recovery attempts remains an open question. In part, this reflects the difficul-
ties inherent in preparing for and responding to phenomena which may occur at any
time, anywhere off southern California, and which may vary-in size from 1-1,000,000

436

gallons and cover tens of square miles, under a wide range of environmental
conditions.

This problematical status also reflects the fact that the three southern
California oil spill cleanup cooperatives -- industry's main line of defense
against-offshore spills -- were established after the Santa Barbara blowout and
have not yet had the opportunity to demonstrate their capabilities duringa major
offshore oil spill. Each cooperative conducts periodic at-sea equipment demon-
strations, to which government and industry officials are invited, but none-of
the cooperatives conduct full-scale rehersals of spill response procedures.
This being the case, the ability of existing procedures and equipment to contain
and recover spilled oil at sea in a timely-fashion under a range of environmental,
conditions is simply unknown.

Considering the variety of oil spill sources, the uncertainties as to the
fate of -spilled oil, the complexities of predicting spill trajectories, the very
real threat of damage from spilled oil, and finally the spill r 'esponse capability
available in southern California today, the need for protection strategies cannot
be underestimated. Three basic protection strategies are proposed: prevention,
at-sea cleanup, and defensive precaution.

P R E V E N T 1 0 N

Prevention is the best solution to the oil spill problem. At existing off-
shore oil and gas leases, careful industry procedures, together with vigorous
government enforcement of spill prevention regulations, can minimize the number
and vol'ume of spills. Advances in drilling, production and safety technologies
can further reduce the incidence of spills. After the 1969 blowout, state and
federal authorities strengthened existing spill prevention regulations, imposing
new requirements, and the U.S. Geological Survey increased its Pacific OCS
inspection force from two to 11 full-time employees. As a'result, there has not
been a reported spill from a production platform in state or federal waters off
California since December, 1969. California OCS oil-related activities are going
to increase as additional leases are brought into production, and to maintain
existing levels of enforcement in the future USGS will have to expand its enforce-
ment staff and budget.

Another way to prevent oil spills is to reject altogether or attach special
conditions to proposed activities with spill potential. These decisions should
be based on oil spill trajectory analyses and on the identification of particularly
important coastal and ma-rine resources vulnerable to spills from the proposed
activity. These analyses can identify sites from which spills would have unusu-
ally large potential for causing damage. Based on this knowledge, proposals can
be denied or shifted to less risky locations, or special conditions can be
imposed to provide a larger-than-ordinary safety margin against oil spillage.
During Lease Sale #35, for example, Santa Monica Bay tracts were withheld from
sale because the potential risks associated with activities there were judged to
outweigh the oil and gas benefits, and special conditions were imposed on leases
in close proximity to Santa Barbara and Santa Cruz islands. California has
recommended a series of similar actions for many of the tracts proposed by the
Interior Department to be leased in Lease Sale #48.

AT S E A C L E A N U P

No offshore oil facility can be made spill-proof, because many spills occur

437

as a result of accidents or human error. In view of the large and growing number
of oil-related activities off California, major and minor oil spills are likely
to occur despite the best efforts of industry and government. When a s.pill
occurs, the primary objective of the response is to keep damage to a minimum.
The surest way to do so is to contain and remove the spilled oil from the water
as quickly as possible.

Most of the factors influencing the chances for successful recovery of spilled
oil at sea -- local sea conditions, size and location of the spill, time of day,
etc. -- are fixed by therandom circumstances of the spill and cannot be altered.
One of the decisive factors which can be influenced is the response time, the lag
between a spill and the deployment of containment boom at the scene. Under
existing regulations, offshore producers store only minimal amounts of contain-
ment boom at offshore platforms and rely on centrally located, shore-based equip-
ment delivered by boat forresponding to spills larger than five or ten barrels.
Joint ownership of this equipment reduces costs to individual operators and
ensures uniform equipment for all member companies. Also, the central onshore
location simplifies the task of maintaining and preparing the equipment for emer-
gency response. But it also builds needless delay into the response time for
spills larger than five to ten barrels. Several existing production platforms in
the Santa Barbara Channel, for instance, are more than 30 miles from the Clean
Seas, Inc. storage yard in Carpinteria.

The delay in delivering containment equipment to these platforms by boat,
the only transportation now available, would be considerable. An obvious solu-
ti.on is to maintain more heavy-duty containment boom at offshore platforms as a
stop-gap measure. This would not increase the' operational limits of existing
containment equipment, nor e'liminate the need for recovery devices and containment
boom stored at central onshore locations. But by requiring that more containment
boom be stored at production platforms, USGS and the State Lands Division could
improve the odds of early at-sea recovery of spilled oil, reducing the potential
for damage from major spills.

D E F E N S I V E P R E C A U T 1 0 N

When it is impossible to contain and recover spilled oil at sea, it is some-
times possible to reduce shoreline damage. Containment booms or, in extreme
cases where no alternative is available, dispersants can be used to keep oil away
from specific areas, by diverting it or by changing its physical properties so
that natural forces move it toward areas judged to be of lesser value, whether
natural or human, or lesser vulnerability.

ESTUARIES, SALT MARSHES, AND WETLANDS

Estuaries, salt marshes and wetlands, for example, are highly productive
areas that provide essential habitats for many coastal and marine species. Oil
entering such areas may cause substantial damage. Moreover, it is particularly
difficult to remove oil from marshes and wetlands, and cleaning such areas once
they have been oiled is apt to cause as much damage as the spilled oil itself.
Estuaries, salt marshes and wetlands, therefore, deserve special protection during
oil spill emergencies. Because these areas generally have restricted communica-
tion with the ocean, defensive booming is a practical protection strategy.
Depending on the circumstances, booms could be set across the entrance to such an
area either to steer the arriving oil to a skimming site, to,deflect the oil to

438

either side of the entrance, or simply to delay or reduce the amount of oil
entering. Defensive booming is unlikely to keep all oil away from the protected
areas, but it can significantly reduce the fouling and damage suffered by sensi-
tive and valuable resources.

Industry has already taken the first step.toward such a protection strategy
in the Santa Barbara Channel. In a study commissioned by Arco, biologist June
Lindstedt-Siva has identified ten biologically valuable areas along the Channel
coast deserving special protection. 161/ Four of these are estuary, salt marsh
and wetland sites between Goleta and Point Augu suitable for defensive booming. 162/
Clean Seas, Inc., the cooperative responding to spills in the Channel, is in the
process of deploying five vans carrying containment boom and other spill cleanup
equipment at Morro Bay, Gaviota, Port Hueneme, and Santa Barbara, for the stated
purpose of protecting harbors, estuaries, and other coastal resources. A sixth
van is maintatned at the central Clean Seas, Inc. yard in Carpinteria. Clean
Coastal Waters, Inc., the cooperative responding to spills in state waters from
Point Dume to the Mexican border, has not yet taken comparative action.

BEACHES AND ROCKY INTERTIDAL AREAS

Other coa&tal resources are not suited for defensive booming. Rocky inter-
tidal and beach areas, for example, generally are too extensive for such tactics
to be effecitve. As with salt marshes, no effective method has been devised for
cleaning oiled rocky intertidal areas, since the two primary methods used in the
past -- steam cleaning or detergent washing -- were found to kill organisms
surviving the original spill. In comparison, oiled beaches are considerably
easier to clean. Three specific rocky and sandy beach areas in the Santa Barbara
Channel area have been proposed as-possessing special bioloqical siqnificance
particularly for the repopulatiom of damaged areas after a large spill. 163/ For
these areas, at-sea containment and removal would be best, with the use blf7dis-
persants or other cleanup agen -ts held in reserve as a final option to be
exercised only after a review by the Regional Response Team.

PINNIPED ROOKERIES

Pinnipeds are disturbed by all human activities. Both defensive booming and
the cleaning of oiled rookeries and haul-out sites are self-defeating strategies,
because the actions themselves would constitute significant disruptions. Pro-
tection strategies must focus on preventing Spilled oil from reaching pinni .ped
rookeries and haul-out sites, either through the prohibition of oil-related
activities in locations where spills would move towards pinniped sites or by
requiring additional containment boom and skimmers at oil-related facilities in
such areas. If spills occur and move toward pinniped sites despite these
precautions, no further defense may be feasible.

439

FOOTNOTES

1. National Academy of Sciences, Petroleum in the Marine Environment
Washington, D.C.: National Academ.v of Sciences, 1975), PD. 1-16.

2. Ibid., p. 104. Percentaqe contributions added.

3. U.S., Federal Energy Administration, North Slope Crude: Where To? How?
IV-E (November 1976), p. 81.

4. Ibid., p. 89.

5. A good discussion and analysis of oil spill statistics is contained in
J. W. Devanney III and Robert J. Stewart, Bayesian Analysis of Oil Spill Statistics,
oresented at the January 1974 meetinq of the New England Section of The Society of
Naval Architects and Marine Enqineers (October 1974). See also V. F. Keith and
J. D. Porricelli, "Analysis.of Oil Outflows due to Tanker Accidents," ProceedinqS
of Joint Conference on Prevention and Control of Oil Spills (14ashingto-n, D.C.:
American Petroleum Institute, 1973).

6. U.S., Fpderal Enerqv Administration, on. cit., oo. 93-94.

7. U.S., Department of the Interior, Geological Survey, estimates that 10,000
barrels of oil were spilled in the first ten days of the blowout. A. A. Allen, in his
report to the U.S. Senate Interior Committee Subcommittee on Minerals, Materials, and
Fuels (1969) Santa Barbara Oil Spill, estimated that 77,000 barrels of oil were
discharged during the first 100 days after the sli0. Foster et al., Santa
Barbara Oil Spill, Part 1: Initial Quantities and Distributio-n6-f-Pof-liltant Crude
T2_@ I
Oi-T_,_E-nv-ir_onmental Pollution , on. 97-133, estimated that between 78,000 and
780,000 barrels of oil were spilled.

8. Al'pine Geophysical Associates, Inc., Oil Pollution Incident: Platform
Charles, Main Pass Block 41 Field, Louisiana (May 1971).

9. Elmer P. Danenberger, Oil Spills, 1971-75, Gulf of Mexico Outer Continental
Shelf, U.S. Department of the Interior Geological SurveY Circular 741, p. 47. Esti-
7m_a_t_eU inputs are taken from National Academv of Sciences, oo. cit., with "Percentage
of Total" figures computed by U.S. Geological Survey.

10. J. W. Devanney and R. J. Stewart, ."Analysis of Oil Snill Statistics,"
Primary Physical Impacts of Offshore Petroleum Developments (Cambridge: Massachu-
setts I'nstitute of Technology, April 1974). See discussion in U.S. Department of
the Interior, Bureau of Land Management, Final Environmpntal Statement: Pronosed
1975 Outer Continental Shelf Oil and Gas General Lease Sal-e Offshore Southern
California (1975), 1, pp. 32-87.

11. U.S., Department of the Interior, Bureau of Land Management, op. cit., p. 85.

12. Don E. Kash et al., Energy Under the Oceans (.1jorman, Oklahoma: University
of Oklahoma Press, 197-3)-,r). 292.

13. Ibid., D. 287.

14. H. T. Cypher, Acting USGS Oil and,Gas Supervisor, Pacific Area, "Tabulation
of Accidents -- Federal Oil and Gas Operations in the nuter Continental Shelf,
Pacific Area," unpublished memorandum, August 4, 1976.

440

15. Letter from Ralph- J. Bowman, Uni-on Oil Company of California, to Trevor
O'Neill, OCS Project staff, March 2, 1977.

16. U.S., Federal Energy Administration, op. cit., D. 151.

17. From National Academy of the Sciences, op. cit., n. 6, Table 1-5. Tanker
contribution (LOT [Load-on-TOP]-t-ankers, non-LOT tankers, terminal operations, tankEr
accidents) estimated to be 1,283,000 tons/year. Tanker accidents contribute 200,OOC
tons/year or 15.6%. LOT tankers, non-LOT tankers, and terminal operations contribute
19083,000 tons, or 84.4%.

18. Interview with Walter Putman, Inspector, California Department of Fish
and Game, March 1977.

19. Interview with Dr. Peter Fischer, California State University-Northridoe,
October 1976.

20. Interview with Dr. Ed Welday, California State Lands Division, March 1977.

21. California Resources Agency, The Offshore Petroleum Resource (1971), p. 137.

22. Interview-with William Gesner, Santa Barbara County Environmental OualitY
Advisory Board:, March 1977.

23. Danenberqer, op. cit., D. 29.

24. Ibid., p. 1.

25. U.S., Department of the Interior, Bureau of Land Manapement, on. cit.,,
II, p. 155.

26. National-Academy of Sciences, ibid., n. 45*.

27. Ibid., p. 46.

28. William D. Garrett, "Impact of Petroleum Spills on the Chemical and
Physical Droperties of the Air-Sea Interface," Santa Barbara Oil Symposium:
Offshore Petroleum Production, An Environmental Inquirv (Santa Barbara,.California,
December 1970) p. 91.

29. Ronald L. Kolpack, ed., Biological and Oceanographical Survey.of the Santa
Barbara Channel Oil Spill, 1969-1970 (University of Southern California:. Allen
Hancock Foundation, 1971), II,_`pp__._T4l-343.

30. See.Max Blumer and Jeremy Sass, "Oil Pollution: Persistence and Deqrada-
tion Of Spilled Fuel Oil.," Science, 176.(June 9, 1972), no. 1120-1122; and Koloack,
op. cit.

31*. Max Blumer, "Scientific Asnects of the Oil Spill Problem," Environme@ntal
Affairs, I (April 1971),'D.-63. ,

31a.,National Academy of Sciences, op. cit@_, D. 66.

32. U.S., Department of Commerce, National Oceani.c and.Atmospherir, Administra-
tion, Deepwater Ports Project Office Pnalysis of the Risk of Damage to the States
of Florida and Louisiana from the LOOP, Inc.., Pronosed Deeowater Port, 1976, op-77-2-6.

441

33. Ibid., P. F-2.

34. See, for example, ibid., p. F-3, Figure F-1 and also MIT, A Review and
Evaluation of Basic Techniques for Pred-icting the Behavior of Surface Oil Slicks,
1976, Table 1, p. 3-65.

35. One researcher found the wind factor to be a function of wind speed;
that is, a different percentage factor-at different wind speeds. See Wu (196R)
in MIT, op. cit., p. 3-65.

36. For example, Hughs (1956) found 0.30 deflection to the left. See MIT,
op. cit., Table 1, D. 3-65.

37. NOAA, on. cit., p. F-4.

38. See MIT, op. cit., Figure 4.5-1, p. 4-64. Also see J. W. Devanney III,
Estimates of Spill Trajec ory Likelihoods for the Southern California OCS, Martin-
gale Technical Report 75-2, 1975, D. 23.

. 39. For an example of how tidal forces can be included in a spill trajectory
model, see Woodward-Clyde, The Importation of Alaskan Crude Oil to the Port of
Long Beach -- An Evaluation of Hypothetical Spills and their Migration, July 1976,
especially pp. Al-A4.

40. A number of useful summaries of the general ocPanography and meteorology
of the Southern California Bight and OCS are in print. See, for example:
K. 0. Emey@y, The Sea Off Southern California (Nei%j York: John Wiley
and Sons. Inc.. 1960).

State Water Pollution Control Board, Publication #20. Oceanographic
Survey of the Continental Shelf Area of Southern California, 19 .59

State Water Quality Control Board, Publication #27. An Oceanographic
and Biological Survey of the Southern California Mainland Shelf, 1965.

United States Department of the Interior, Bureau of Land Management.
Final Environmental Statement -- Proposed 1975 Outer Continental Shelf Oil and
Gas General Lease Sale Offshore Southern California (OCS Sale #30-,1975.
United States Department of the Interior, Geological Survey. Final
Environmental Statement -- Oil and Gas Development in the Santa Barbara Channel
Outer Continental Shelf Off California, 1976-.

Western Oil and Gas Association. Environmental Assessment StudL_Z_
.1
Proposed Sale of Fe-deral Oil and Gas Leases, Southern California Outer Continental
Shelf, 1974.
41. Richard Schwartzlose and Joseph L. Reid, "Near Shore Circulation in the
California Current" in California Marine Research Committee, CALCOFI Reports,
XVI (1972), 57-65.
42. State Water Pollution Control Board, Oceanographic Survey of the
Continental Shelf of Southern California, Publication #20, 1959, pp. 24-26.

442

43. Schwartzlose and Reid, op. cit., pp. 57-58.

44. Naval Weather Service Command, Fleet Weather Facility, Climatological
Study, Southern California Operating Area, 1971.

45. Devanney, op. cit., p. 5.

46. J. G. Wyllie, Geostrophic Flow of the California Current at the Surface
and at 200 Meters California Cooperative Oceanic Fisheries Investigations, Atlas #4,'
1966.
47.* Kolpack, op. q@jt.; and Kolpack, "Relationship of Migration of Natural Seep
Material to Oceanography of Santa Barbara Channel," unpublished report, August 1976.

48. Intersea Research Corporation, "Study of Potential Trajectories of Oil
Spilled in the Proposed Southern California Offshore Lease Area," in Western Oil
an-d Gas Association Environmental Assessment Study -- Proposed Sale of-Federal Oil
and Gas Leases, Southern California Outer Continental Shelf, Appendix 3, 1974.

49. Devanney, op. cit.

50. Intersea Research Corporation, op. cit., p. 1.

51. See, generally, Devanney, op. cit., pp. 32 ff.

52. Ibid., p. 116.

53. Intersea Research Corporation, op. cit., p. 31. IRC included neither the
Navy wind summaries nor its own "average" or "dominant" wind vectors in the report.
It is thus impossible to determine the extent to which this apparent methodological
error skewed the ultimate results of IRC's study.

54. Dr. R. J. Stewart, perso.nal communication,to Trevor O'Neill, nCS, Nov. 22, 1976.

55. United States Department of the -Interior, Bureau of Land Management, Final
Environmental Statement -- Proposed 1975 Outer Continental Shelf Oil and Gas General
Lease Sale Offshore Southern California (OCS Sale _#_35_@, 1-975, Volume 2, pp. 425-453
and Volume 4, Appendix 17, pp. 691-725.

56. Ibid; see matrix tables, Volume 4, Appendix 17, pp. 691-725.
57. U.S., Department of the Interior, "Secretary Kleppe Deletes Additional 16
Tracts from the Northern Gulf of Alaska (OCS-39) Sale'," news release, April 6, 1976.

58. See footnote 32.

59. Dr. Jerry Galt, NOAA Pacific Marine Environmental Laboratory, personal com-
r
.iunication to Trevor O'Neill, OCS Project Staff, December 3, 1976.

60. See UCLA Environmental Science and Engineering Department, Southern
California Outer Continental Shelf Oil Development: Analysis of Key Issues, 1976.
.pp. 4.9 to 4.33.

61. Richard A. Smith et al., An Oil Spill Risk Analysis for the Mid-Atlantic
Outer Continental Shelf Lease Area., U.S. Geological Survey,, Open-File Report 76-451,
June 1976.

443

62. See Richard A. Smith et al., An Oilspill Risk Analysis for the North
Atlantic Outer Continental Shelf Lease Area, U.S. Geological Survey, Open-File
Report 76-620, 1976, and James R. Slack and R. A. Smith, An Oilspill Risk Analysis
for the South Atlantic Outer Continental Shelf Lease Area, U.S. Geological Survey
Ope.n-File Report 76-653, 1976.

63. Bureau of Land Management, Pacific OCS Office, personal communication.,
December 2, 1976.

64. Numerous summaries of the reported and potential effects of oil on coastal
and marine organisms are in print. See, for example, Donald F. Boesch et al.,
Oil Spills and the Marine Environment, 1973; National Academy of Sciences, OP. cit.;
California State Lands Division, Draft Environmental Impact Report, Development o
South El-wood Offshore Oil Field, Appendix A, 1914; bureau ot Land management ' Final
Environmental Impact Statement, OCS Sale #35, 2R. Li@t., and U.S. Department of the
Interior, 1975, 11, pp. 141 ff.

65. Boesch et al., op. cit., pp. 35 ff.

66. Max Blumer, "Scientific Aspects of the Oil Spill Problem," Environmental
Affairs, I (April 1971).

67. Dale R. Evans and Stanley D. Rice, "Effects of Oil on Marine Ecosystems:
.A Review for Administrators and Policy Makers," Fishery Bulletin, LXXII (1974), 3.

68. Woodward-Clyde, Draft Environmental Impact Report for Resumption of Drill-
ing in the'Santa Barbara Channel from Existing Standard Oil Company of California
Platforms, 1976, p. 111-78.

69. See, for example, Clayton D. McAuliffe et-al., "Chevron Main Pass Block 41
Oil Spill: Chemical and Biological Investigatio@`s,T`in Proceedings, 1975-Conference
on Prevention and Control of Oil Pollution, 1975.

70. See, for example, Erich Gundlach et-al., "Black Tide of La Coruna,"
Oceans, X (March-April, 1977).

71. Goldacre, Biological Effects of Oil Pollution on Littoral Communities,
Carthy and Arthur, eds., 1969.

72. @Iax RElumer, op. cit., p. 56.

73. Memorandum from Hatch and-Parent (legal counsel to Exxon), to California
Coastal Zone Conservation Commission,-September 31-1975.

74. Max Blumer, G. Souza, and J. Sass, "Hydrocarbon'Pollutton of Edible
Shellfish,by an Oil Spill," Marine Biology, V (March 1970), p. 195.

75. G. T. Philipps, Geochem ica Acta, no * 29 (1965), pp. 1021-1049, quoted by
Max Blumer, "Comments on the Report by Dr. Dale Straughan, 'Biological and Oceano-
graphical Survey of:the Santa Barbara Channel Oil Spill, 1969-1970, Volumes 1 and 2',"
unpublished letter report to Maine Environmental Improvement Commission, March 29, 1971.

76. Interview with Dale Straughan, March 1977; and Dale Straughan, "Biological
Survey of Intertidal Areas in the Straits of Magellan in January, 1975, Five Months
after,the Metula Oil Spill," unpublished manuscript.

444

77. For synopsis of Argea Prima, Chryssi P. Goulandris, and Ocean Eagl
spills, see National Academy of Sciences, op. cit., p. 74. For Urquiola spill,
see Erich Gundlach, op. cit.

'78. California Resources Agency, op. cit., p. 138.

79. Ibid.

80.- National Academy of Sciences, op. cit., pp. 83-84.

81. Burney J. LeBoeuf, "Oil Contamination and Elephant Seal Mortality: A
Negative Finding," p. 280, in Dale Straughan, Biological and Oceanographical
T-
Survey of the Santa Barbara Channel Oil Spill, 969-1970, 1, Biology and Bac-
teriology (1971).
82. J. E. Smith, ed., "Torrey Canyon" Pollution and Marine Life: A Progress
Report by the Plymouth Laboratory, Cambridge University Press, 1968.

83. Ibid.

84. A. Nelson-Smith, Oil Pollution and Marine Ecology (London: Elek Science)
1972.

85. N. L. Nicholson and R. L. Cimberg, The Santa Barbara Oil Spills of 1969:
A Post-Spill Survey of the Rocky Intertidal, 1971, pp. 325-400, in D. Straughan,
ed., Biolo@ical and Oceanographical Survey of the Santa Barbara Channel Oil Spills,
1969-1970 (Los Angeles: Allan Hancock Foundation, University of Southern California).

86. R. Kanter, D. Straughan, and W. N. Jessee, "Effects of Exposure to Oil on
Mytilus Californianus from Different Localities," in Proceedings, Joint Conference
on Prevention and Control of Oil Spills (Washington, D.C.: American Pe-t-ro-T-eum
Institute), 1971.

87. Dale Straughan, Sublethal Effects of Natural Chronic Exposure to Petroleum
in the Marine Environnent, American Petroleum Institute, Publication 4280, 1976.

88. See, for example, J. M. Baker, "Successive Spillages," in E. B. Cowell,
Proceedings of the Symposium on the Ecological Effects of Oil Pollution on Littoral
Communities (London: Institute of Petroleum, 1971). See also P. G. Jeffrey, "Large-
scale experiments on the spreading of oil at sea and its disappearance by natural
factors," in Proceedings, Joint Conference on Prevention and Control of Oil Spills,
1973.

89. Max Blumer et al., "A Small Oil Spill," Environment, XIII (March 1971).
See also Blumer,-Souza, and Sass, op. cit., pp. 195-202.

90. Interview with George Hampson, Woods Hole-Oceanographic Institution,
March 1977.

91. Ibid.

92. A. A. Allen, op. cit.

93. Dale Straughan, ed., Biological an-d Oceanographical Survey of the
.Santa Barbara Channel Oil Spill, 1969--1970 (Los Angeles: Allan Hancock Founda-
tion, University of Southern California, 1971).

445

94. Dale Straughan, `Ecological Effects of the Santa Barbara Oil Spill,"
Santa Barbara Oil Symposium -- Offshore Petroleum Production, An Environmental
Inquiry (University of California-Santa Barbara, 1970), pp. 180-181.

95. Max Blumer et al., "A Small Oil Spill," op. cit., pp. 9-10.

96. Max Blumer, letter to Maine Environmental Improvement Commission, op.
cit., passim.

97. J. H. Connell, '.'Submission to the Royal Commission-on Oil Exploitation
on the Great Barrier Reef: A Review of D. Straughan, Biological and Oceanographi-
cal Survey of the Santa Barbara Channel Oil Spill," I, Biology and Bacteriology
T1971), pp. 11-12.

98. Kristian Fauchald, "The Benthic Fauna in the Santa Barbara Channel
Following the January 1969 Oil Spill," in Dale Straughan, Biological and Oceano-
graphical Survey of the Santa Barbara Channel Oil Spill, I, i3iblogy and Bacteriolo@Ly
(1971), p. 73.

99. Dale Straughan, "Ecoloqical Effects of the Santa Barbara Oil Spill," op.
.cit., p. 175.

100. The USC study did not prove that significant and lasting damage did not
occur,as a result of the blowout; as Straughan carefully concludes, the study was
only unable to prove that such.damage did occur.

101. W. J. Mead and P. E. Sorenson, "Estimate of the Costs of.the Santa
Barbara Oil Spill of 1969," Draft Environmental Statement, Oil and Gas Development
in the Santa Barbara Channel Outer Continental Shelf Off California, III, Depart-
ment of the Interior, pp. 183-185.

102. Interview with George Souza, Shellfish Warden of West Falmouth, August
1976 and April 1977.

103. On March 18, 1977, as this study was in final preparation, President
Carter, in a message to Congress, proposed a federal program for reducing the
incidence of oil spills and providing a $200 million federal fund to be used both
for cleanup of spills and for compensation of damages caused by them. As reported
by The Washington Post, the President's program includes six proposals: (1) a
single new law to fix responsibility for spills regardless of their source, sup-
planting presently fragmented state and federal laws; (2) ratification by the U.S.
Senate of the 1973 International Convention for the Prevention of Pollution from
Ships, whi'ch prohibits purging of tanker holds into sea waters; (3) an international
conference in the fall of 1977 to set stricter standards for tanker construction,
oil transfer equipment, and inspections thereof; (4) Coast Guard boarding and in-
spection, at least once annually, of every foreign flag tanker entering U.S. waters,
and maintenance of computerized data on all such tankers; (5) development of ability
to respond "adequately" to any spill up to 100,000 tons within six hours (news
reports did not specify the agency to be vested with this responsibility); and'(6)
establishment of the cleanup and compensation fund, source of which was not speci-
fied in local reports.

446

104. U.S.C.A., � 1321. In 1970 following the Torrey Canyon groundinq in 1967
and the Santa Barbara Blowout in 1969, Congress passed the Water Quality Improve-
ment Act of 1970 which added two new sections to the FWPCA, Sections 11 and 12,
dealing with the control of oil pollution and hazardous substances respectively.
These sections were combined and slightly revised in the 1972 amendment to the
FWPCA, becoming Section 311 of the amended act.

105. U.S.C.A., � 1321(j)(1)(C). Executive Order 11735, 38 Federal Reqister
21234 (1973), delegates the President's authority to the Department of Transpor-
tation for vessels and transportation-related onshore and offshore facilities.
The Coast Guard has issued regulations prescribing equipment requirements for oil
transfer facilities and vessels. 33 C.F.R., parts 154-65 (1972). EPA's regula-
tions for non-transportatibn related facilities are found at 38 Federal Register
34161 (1973).

106. U.S.C.A., 1321(j)(2).

107. U.S.C.A., 1321(b)(6).

108. 40 C.F.R., part 110.3.

109. "Outline of Legislation Concerning the Prevention and Clean-Up of Oil and
Hazardous Substances Discharged into 'Haters," prepared for Texas Coastal and Marine
Council, Oil'Spill Primer, June, 1975.

110. U.S.C.A., � 1321(b)(5). Notification, of course, opens the discharger to
clean-up liability and civil penalties, but failure to notify the Coast Guara is a
criminal.offense punishable by fines up to $10,000 and one year's imprisonment
(33 U.S.C.A., � 1321(h)(5). Compliance with the duty to report spills does not
appear to bar criminal prosecution under the 1899 Refuse Act, 33) U.S.C.A., � 407,
which prohibits discharges into navigable waters without a permit with sanctions
including one year's imprisonment (U.S. v. Mobil Oil Corporation, 464 F 2d 1124
(5th Ci r@. , 1972) .

111. U.S.C.A., � 1321(C).

112.. See Don Kash et al., op. cit., pp. 166-169.

113. U.S.C.A., � 1321(C). For a more detailed discussion of the National Contingency
Plan and an assessment of federal, state, local, and private industry cleanup caDabili-
ties, see Section 5 of Governor's Office of Plannina @nd Research, O@CS Project Task
Force, Offshore Oil and Gas Development: Southern California (Prelim. Draft), Aug. 1976.
114. U.S.C.A., � 1321(k).
115. The 1976 Deziartment of Transportation Appropriation Act (Pub. L. 94-134, 89
Stat. 695) included @10 million to replenish the Fund. See Maxine Li - p-el- e-s, Oil: Study
of Pollution Insurance Liability Laws, Environmental Policy Instif6te, Washington,
D_.-C-.-,- April. 1976, p. 17.

116. C.F.R., pt. 250.43(b).

117. Don E. Kash et al . , U. ci t. , p. 165; Lance D. Wood, "Requi ri ng Pol 1 uters
to Pay for Aquatic - N-atural Resources Destroyed by Oil Pollution," 8 Natural
Resources Law 556 (1976); Charles Lettow, "Marine Pollution," in Environmental
L,ai.,, Institute, Federal Environmental Law (1974), p. 672.

447

118. U.S.C.A., � 1321(f).

119. U.S.C.A., � 1321(c)(2)(H).

120. U.S.C.A., � '1321(f).

121. Ibid.

122. Lance D. Wood, op. cit., pp. 556, 575.

123. U.S.C.A., � 1321(o).

124. C.F.R. 250.43(c).

125. Phil Van Voorhis, "Pollution Fund Statistics," memorandum to Chief of
Marine Environmental Protection Division and Chief of BUdqet Division, U.S. Coast
Guard, April 12, 1974, cited in Lipeles, op. cit., p. 18.

126. North Slope Crude: Where To? How?, Federal Energy Administration,
San Francisco, California, IV-89, November 1976.

127. See, e.g., Oppen v. Aetna Insurance Company, 485 F2d 252 (1973); Union
Oil Company v. Oppen, 501 F2d 558 (1974); Peti tio n of New Jersey Barging Corpora-
tion, 168 F. Supp 925 (1956); Burqess v. M/V Tamano, 370 F. Supp 247 (1973).

128. Ibid. See Green v. General Petroleum Corporation, 205 Cal. 328, 270 0. 952
(1928).

129. Interview with Barry Cappello, City Attorney Santa Barbara, AUqUSt 119, 1976.
Plaintiffs included City and County of Santa Barbara, City of Carpinteria, and State
of California.

130. In Santa Barbara, for example, it was not until May 1, 1970 -- more than 16
months after the January 28, 1969, spill -_ that fishermen entered a stir)ulation with
Union Oil Company that."all legally compensible damages" would be compensated. It
was another four years before litigation ended disputes over the damages allowed
by that settlement agreement, Union Oil Company v. Oppen, 501, F2d 558 (1974).
131. Black's Law Dictionary, 466 (4th ed., 19681J.
132. Burgess v. M/V Tamano, 370 F.Supp. 247 (1973).

133. Union Oil Co. v. Oppen, 501 F2d 558.

134. Burgess v. M/V Tamano, 370 F.Supp. 247, 251.

135. Union Oil Co. v. Oppen, 501 F2d 558, 570.

136. Recovery granted: Carbone v. Ursich, 209 F2d 178; recovery denied:
Casado v. Schooner Pilgrim, Inc., 171 F.Supp. 78; Guarassi v. Panama Canal Co.,
271 F.Supp. 678; Henderson v. Arundel Corp., 262 F.Supp. 152.

137. Petition of New Jersey Barging Corp., 168 F.SuDp. 925.

138. Oppen v. Aetna Insurance Co., 485 F2d 252.

448

139. In the litigation by the City and County of Santa Barbara, City of
Carpinteria, and State of California stemming from the 1969 Santa Barbara blowout,
Union Oil did not object to loss of proprietary income as a damage element.
140. Burgess v. M/V Tamano, 370 F Supp. 247 (upheld the State's right to recover).

141. California et al. v. Union Oil et al., Civil Action No. 69-1-68-RM
(C.D. Cal), Memorandum of Defendants Re: Suggested Procedure to Facilitate Settle-
ment and Disposition of Case.- May 10,1973.

142. DEIS, OCS Sale #35, vol. 2, pp. 38-39; FEIS, OCS Sale #35, vol. 2, p. 85.

143. A good description of the equipment and procedures tried out during the
blowout is contained in Tetra Tech, Inc., Environmental Assessment Report, Crude
Oil Transportation System: Valdez, Alaska to Long Beach, California -- Sea Lea,
Appendix C, pp. C21-25.
144. 40 C.F.R., Chapter V, Part 1510 : The Coast Guard has issued a regional
plan for Federal Region 9, including California, Arizona, Nevada, and Hawaii, and
a subregional plan for Coast Guard District 11 (Mexican border to the southern
border of San Luis Obispo County).

145. United States Departments of the Interior and Transportation, "Memorandum
of Understanding," August 10, 1971. Published inter alia, in United States Depart-
ment of the Interior, Regulations.Pertaining to Mineral Leasing, Operations and
Pipelines on the Outer Continental Shelf, August, 1975.

146. In state @,!aters, Californ-ia's Department of Fish and Game has final
authority over the use of chemical agents. In federal waters, the Coast Guard
shares authority with EPA. Within 500 yards of all OCS facilities, USGS controls
all abatement and clean-up measures.

147. There are actually two contingency plans at the state level. Under the
State of California's Oil Spill Contingency Plan itself, the Department of Fish
and Game (DFG) in the Resources Agency plays the leading role. DFG has constructed
its own Ofl-and Hazardous Materials Contingency Plan, separate from but compatible
with the state plan.,

148. Pacific OCS Order P7. Also, see 30 C.F.R. 250.34.

149. The State Lands Division oil.spill contingency plan requires all drilling
and production activities on existing leases in State waters. See California State
Lands Commission, Procedures for Drilling and Production Operations from Existing
Facilities on Tide and Submerged Lands.Currently Under State Oil and Gas Leases.
7he Environmental Protection Agency requires operators of all non-transportation-
related facilities -- such as drilling rigs and production platforms -- in navigable
waters (out to three miles offshore) to prepare Spill Prevention, Control and
Countermeasure Plans (SPCCs). See 40 CFR 112. The Coast Guard imooses comparable
requirements on vessels and transportation-related facilities in naviqable waters.
See Memorandum of Understanding between the Secretary of Transportation and the
Administrator of the Environmental Protection Agency, November 24, 1971.

150. Smaller amounts are.owned and stored by the Coast Guard at its Pacific
Strike Force base at Hamilton Air Force Base and at its Terminal Island base. As
well, some of the operators maintain-equipment at refineries and marine terminals.

449

151. Interview with Jack Hundley, Arco, April, 1977.

152. According to Section 2001.3 of Annex 10 to the National Plan: "This
Schedule advocates development and utilization of sorbents, skimmers, booms, and
other mechanical control methods to remove or miticate oil *" According to Section
2301 of California's Oil Spill Cleanup Agents (OSCA) Rules and Regulations,
the board (State Water Resources'Control Board, which administers the regulations)
advocates development and utilization of mechanical and other control methods that
will result in removal of oil from the environment with subsequent Proper disposal.

153. For an excellent summary of oil spill response equipment, see Tetra-Tech,
Inc., op. cit., Appendix C.

154. See California Department of Fish and Game, Oil-Spill Procedure Guide,
February 1975 revision.

155. Don E. Kash et al., op. qLit., pp. 74-75.

1"56. As for most spill response equipment, it@is quite difficult to pin down
the exact sea state at which any particular skimmer becomes ineffective. Clean
Seas, Inc.;, in its o@,jn descriptive brochure, states that its heaviest-duty and
largest-volume skimmer "will operate successfully in moderate sea states"
(emphasis,added). In the same brochure, CSI characterizes its "Sea Dragon"
skimmer as "operable in a moderate sea state," and its Mack II-skimmer as capable
of functioning in "light to moderate sea states."

157. Title 23, Subchapter:10, California Administrative Code.

158. J. E. Smith, op. cit.

159. Under Section 2332 of California's OSCA rules and regulations,dispersants
may not be applied-to shorelines and may be used in State waters "only if waterfowl
areas, recreational beaches, marinas, or shore facilities are threatened;*and
mechanical control devices or collecting agents are Judged to be inadequate-or in--
feasible by.[DFG or SWRCB]." Section 2003.1 of Annex 10 to the National Plan
provides that "Dispersing agents may be used in any place, at any time, and in
quantities designated by the OCS (Coast-Guard On-Scene Commander or Coordinator)
when.their use will:
--In the judgment of the OSC, prevent or substantially reduce hazard to human life
or limb or substantially reduce explosion or fire hazard to property;
--In the judgment of the EPA RRT member or on a case-by-case basis, in consultation,
whenever possible, with appropriate state and federal agenci-es, prevent or reduce
substantial hazard to a major segment of the population(s) of vulnera'_,le species
of waterfowl; or
--In the judgment of the EPA RRT member on a case-by-case basis, in consultation,
whenever possible, with appropriate state.and federal aqencies, result in the least
overall environmental damage, or interference with designated water uses."

160. Interview with Harold Takanake, EPA respresentative to District 9 Regional
Response Team (which advises Coast@Guard on spill cleanup operations,off California
and Hawaii), April 1977.

450

161. June Lindstedt-Seva, Oil Spill Response Planning for Biologically
Sensitive Areas of the Santa@'BarbarA MOW, unpublished report orepared for
Atlantic Richfield Co. (ARCO), August 1976.

-162. Goleta Slough, Carpinteria Marsh,-Santa Clara River mouth, and Magu
Lagoon.

163. Point Conception, Naples Beach and reef, and the west end of Santa
Cruz Island. Proposed by Dr. Adrian Wenner, University of California, Santa
Barbara, quoted:in Lundstedt-Siva, op. cit..

30-76658 451

CHAPTER 18

ECONOMIC EFFECTS:
BE'NEFITS VS. BURDENS

The ind ustries involved in extracting and refining crude oil and natural
gas.are beginning to play an increasingly significant role in California's
economy. While total personal income in the state increased from $98,132 million
in 1973, to $104,835 million in 1975, personal income deri-ved from the industries
involved in oil and gas extraction, and petroleum and coal products, increased
from $781 million to $1,121 million during the same period. l/ Thus, over the
three years, the petroleum-related income increased by 44%, @While total personal
income in the state rose by 18%.

'Such figures suggest that the economic impact of Lease-Sale #35 on southern
California must be very sizeable. However, work completed by the Governor's Office
of Planning and Research, Onshore Impact of Offshore Southern California OCS Sale
No. 35 for convenience, referred to as OCS Sale No. 35 in future pages, does not bear
this out. 2/ Extrapolating from the projections in this report, we have attempted.
to calculate, as accurately as possible, the nature and scal-e of the economic
impacts of Lease Sale #35 on the southern California region from the sub-county
level to the regional five-county level.

In other studies of this type, input-output techniques have been used to fore-
cast employment and income resulting from OCS development."However, since that
method is based on a series of very rigid assumptions which generally have national
rather than regional application, it was not used here for analysis of Lease Sale
#35, where the anticipated economic impacts affect a relatively small area.
Appendix I contains a more detailed discussion of input/output analysis, along
with our reasons-for rejecting it in our report. As for the method we have used
which will prove both more reliable and more serviceable for staffs of local and
state agencies, a general cautionary word is in order: because the best available
employment data pertain to the Southern California region as a whole, our calcula-
tions for regional employment and income may be expected to have greater reliability
than the estimates at county level.

We wish to acknowledge with gratitude the assistance of Professor David
Starrett of Stanford University in the development of an overall analytical
framework for assessing regional economic effects of OCS activity.

For example, see Thomas Grigalunas, Offshore Petroleum and New England,
University of Rhode Island, 1975.

453

Given the mobility of labor throughout the southern California region,
county-specific projections of economic impacts can only serve as general
indicators of future economic effects. As more reliable data become available,
particularly after the initial exploration phase has been completed, local
governments may extend this analysis to obtain closer estimates of effects.
Although we have restricted our efforts here to the effects of Lease Sale #35
on Ventura, Orange, and Los Angeles counties, our method can also be applied to
the Santa Barbara Channel tracts, as well as to future lease sales, such as
#s 48 and 53. Consequently, local government will be able to assess the cumula-
tive effects of several lease sales.

The report first presents scenario development at both the regional and
sub-regional levels. It then analyzes the economic impacts of the following:

1. effects on induced employment and income, with specific emphasis on
multiplier derivation;

2. effect on prices, with particular reference to housing and consumer
durables;

3. effects on such public services as schools, fire and police protection,
and sewer services; and,

4. effects on taxes and transfers, with attention given to equity con-
siderations.

Following this section, the report gives a brief set of guidelines for use in
analyzing,the economic effects of future sales.

SCENARIO DEVELOPMENT
R E G 1 0 N A L E M P L 0 Y M E N T A N D I N C 0 M E E S T I M A T E S

This section focuses on wage and salary income derived from OCS development,
rather than on capital expenditures for facilities, equipment, or materials. It
is assumed that most such purchases will not take place in the study region, because
of existing capacity or of the probability that construction will take place in other
areas.

In developing its forecast, OCS Sale.,No. 35 distinguishes between potential and
actual effects. Estimates of employment presented in many documents prepared prior
to the actual occurrence of Lease Sale No. 35 were frequently based on the assump-
tion that all tracts offered in that sale would be leased. However, OCS Sale No. 35
stresses that:

Although it would have been impossible to predict that only
56 of the 297 tracts originally offered would actually be
leased, production and employment effects cannot and should
not be based on the assumption that all tracts offered will
be awarded. 3/

454

Even with this information available, OCS Sale No. 35 emphasizes that
employment estimates cannot be derived with a great degree of certainty beyond-
the exploration phase of development. At the current time,

the exploratory phase represents the only "sure employment"
resulting from the lease sale. Assuming that exploration
begins in 1976, and that the first commercial discovery is
made within 2 years, additional employment effects could
then-be calculated with more certainty on the basis of
confirmed discoveries. 4/

Keeping such considerations in mind, the following scenario for regional impact
analysis of Lease Sale #35 has been developed.

OCS operations are divided into three phases -- exploration, development, and
production. At any particular site, these activities occur consecutively, but
within a large field all of the operations may be underway simultaneously. Employ-
ment figures for all phases of operations,are based upon the number of tracts
awarded, 56. Employment and income estimates pertain solely to primary jobs
generated by OCS services and trades.

In the exploration phasei employment hinges upon the number of rig-years
necessary to drill approximately two wells per tract, a total of 112 wells. It is
assumed that four to six rigs will be,in simultaneous operation over a four- to
six-year period of exploration. Assuming four wells are drilled in one rig-year, we
have an expected total of 28 rig-years for the exploratory phase.

The number of platforms required during the development phase depends upon
the estimates of derived resource reserve. We assume that platform fabrication will
take place over a five- to eight-year period, that drilling operations will neces-
sitate a maximum of*20 platforms, and that there will be 1.5 rigs in operation over
,a total of three rig-years per platform. Thus, it is expected that six rigs will
be in operation over a ten-year period -- a maximum 60 rig-years if all platforms
remain in constant use. Estimates of onshore facility construction are rather
questionable owing to the amount of surplus capacity currently available in several
existing processing plants in the area and to possible future consolidation
policies encouraged by the Coastal Commission. The number and size of the anti-
cipated plants is the major variable to be considered. It is assumed that
construction will take place throughout a six- to ten-year period.

Throughout the production phase, the most significant variable is the amount
of resource in place, with particular emphasis given to the number of years of
productive life for each field. We assume productivelife to be approximately
40 years, with the number of years at peak level to be about 20. The major factor
affecting onshore facility operation is the average production per day -- this
we assume to be approximately 100,000 barrels for the 56 tracts. It should be
.noted that employment estimates for refinery workers were,omitted from this
report because of the general uncertainty as to the location of new refineries. 5/

455

Wage and salary income were projected on the basis of estimates presented
in OCS Oil and Gas -- an Environmental Assessment. 6/ These estimates by the
council on Environmental Quality (CEQ) have a greaCer degree of reliability for
the purposes of this report than do the wage and salary listings for workers in
the petroleum and mining industries appearing in the monthly bulletins published
by the Department of Labor's Bureau of Labor Statistics, such as the.Monthly
Labor Review and in 'Employment and Earnings, because the CEQ breaks down wages
and-salaries by the different phases of OCS operations. The following figures
provided by the CEQ for average base earnings, by work category, are presented
in 1970 dollars:

OCS Development Operations CEQ Yearly Salary Estimates

Exploratory Drilling $13,000
Platform Fabrication 12,500
Development Drilling 13,000
Oil and Gas Production
Offshore 10,000
Oil and Gas Production
Onshore Facility Operations* 11,500
Support Services 10,000

A weighting index derived from the average weekly earnings for production or
non-supervisory workers in oil and gas extraction for the period 1970-1975 was
applied to the above estimates to arrive at salary equivalents in 1975 dollars.
The inflationary salary index is as follows:

Time 1970 1971 1972 1973 1974
(From March to March) 1971 1972 1973 1974 1975

Inflationary Wage and 3.0% 6.7% 4.1% 14.9% 16.4%
Salary Increase

After application of the wage and salary index to the CEQ estimates, the
following base projections, in 1975 dollars, were derived:

OCS Development Operations Yearly Salary Estimates

Exploratory Drilling $20,000
Platform Fabrication 19,000
Development Drilling 20,000
Oil and Gas Production
Offshore 15,500
Oil and Gas Production
Onshore Facility Operations 17,500
Support Services 15,500
Onshore Facility.Construction** 14,000

Computed from direct employee compensation in the refinery industry for three
Atlantic regions. $11,500 is the mean value.

-Salaries for construction workers were derived from 1975 weekly gross income
.averages for production or non-supervisory workers, Monthly Labor Review, IC,
(July, 1976). 456

These salary estimates are roughly comparable-to the estimates derived from the
Final Environmental Statements, OCS Sale No. 35, 7/ where it is assumed that the
figures, in 1972-1973 dollars, list Exploratory Drillings at $20,000, Development
Well Drillings at $16,000, and Production Operations at $14,000.

Our CEQ-derived annual wage and salary estimates were then multiplied by
annual employment forecasts in order to determine income derived from each phase
of OCS operations. Tab-le 2 lists annual-employment and-income for each phase
of operations for the lifetime of the project, 1976-2000. These annual figures
are then@summed irr order to present total employment"and total income for each
phase. Table I shows total employment and income forecasts, by year, for all
phases,of.OCS operations. The.sum of employment produced by Lease Sale #35
over the lifetime of the project thus equals 44,380 man-years'and total income
equals 777.30 million dollars.

TABLE'l:
TOTAL EMPLOYMENT AND INCOME IMPACTS BY YEAR AND OVER THE LIFE-TIME OF THE
PROJECT FOR VENTURA, ORANGE AND LOS ANGELES COUNTIES

Total
Year Total Local Imported Income
Employment Employment Employment (Millions of

1976 976 800 176 18-17
1977 1850 1334- 516 35-65
1978 2450 1778 672 47.45
1979 2825 2075 750 54.50
1980 3220 2410 810 61.39
1981 2566 2096 470 47.75
1982 2278 1828 450 41-99
1983 2540 2130 4lu 45-41
1984 2400 2070. 330 42-15
1985 2500 2170 330 43-80
1986 2300 2048 252 39.80
1987 1925 1751 174 32-85
1988 1650 1476 174 28-00
1989 1250 1232 18 20-00
1990 1250 1232 18 20-00
1991-95 1250 1232 18 20.00
1996- 1230 1212 18 19.69

44,380 38,650- 5,730 777-30 (in 1975'
dollars)

Calculated by dividing total.salaries by total employees in each category in
Table III-32.of the Final Environmental Statement, OCS.Sale No..35. See also
Table 111-34 in that document.

457

TABLE 2:
EMPLOYMENT-AND INCOME IMPACTS FOR-VENTURA, LOS ANGELESAND ORANGE COUNTIES

Total Tot I
Total Local Imported Income Total Local Imported In'l
Year Emp Ioyment Employment Employment (Millions of $) Year Employment Emp I oyment Employment (Millions of $)

EXPLORATORY 1976 676 536 140 13.52 SUPPORT 1976 300 264 36 4.65
DRILLING 1977 1550 1070 480 31.0 SERVICES 1977 300 264 36 4.65
1978 1550 1070 480 31.0 1978 300 264 36 4.65
1979 155U 1070 480 31.0 1979 300 264 36 4.65
1980 155U 1070 480 31.0 1980 300 282 18 4.65
1981 676 536 140 13.52
1982 388 260 120 7.
1983 260 180 80 5.20
1984 0 0 0 0 2060 360 28'2 1 *8 4*65

7,500 6,979 522 116.25

2000 0 0 0 0
PRODUCTIO 976 0 0 0 0
8,200 5,800 2,400 164.0 OPERATIONN 11977 0 a 0
1978 0 0 0
1979 0 0 0
PLATFORM 1976 0 0 0 0 1980 80 80 1.24
FABRICATION 1977 0 U 0 1981 160 160 2.48
1978 200 200 3.8 1982 160 160 2.48
1979 300 3DO 5.7 1983 320 320 4.96
1980 300 300 5.7 1984 400 400 6.2
1981 400 40u 7.6 1985 640 640 9.92
1982 400 400 7.6
1983 400 400 7.6
1984 4UO 400 7.6
1985 300 3OU 5.7 1995 640 640 9.92
1986 300 300 6.7 1996 620 620 9.61
1987 200 200 3.8
1988 a 0 0

2000 6ZO 620 0 9.61

2000 0 0 0 0 11,260 11,260 174.53

3,200 3,200 60.8 ONSHORE
FACILITY
DEVELOPMENTAL 1976 0 0 0 0 OPERAT10N 1976 0 0 0 0
DRILLING 1977 0 0 0 0 1977 0 0 0
1978 400 244 156 8.0 1978 0 0 0
1979 600 366 274 12.0 1979 0 0 0
1980 800 488 312 16.0 1980 40 40 .7
1981 goo 488 312 16.0 1081 80 80 1.4
1982 800 488 312 16.0 1982 80 80 1.4
1983 800 488 312 16.0 1983 160 160 2.8
1984 800 488 312 16.0 1984 200 200 3.5
1985 Soo 488 312 16.0 1985 310 310 5.43
1986 bOO 366 234 12.u
1987 400 244 156 8.0
1988 400 244 156 8.0
1989 0 U 0 0 2000 310 310 0 5.43

5,520 5.520 96.68

2UOO 0 0 0 0

7.200 4,392 2,808 144.00

ONSHORE 1976 0 0 0 0
FACILITY 1977 0 0 0 0
CONSTRUCIION 1978 0 0 0
1979 75 75 1.5
1980 150 150 2.1
1981 .150 150 2.1
1982 150 15u 2.1
1983 3DO 300 4.2
1984, 3UO 300 4.2
1985 150 150 2.1
1986 150 150 2.1
1987 75 75 1.05
1988 0 0 0 Ayerage wage and salary income assumptions: EXPLORATORY DRILLING $20,000 in
1975 dollars; PLATFOR14 FABRICATION = $19,000 in 1975 dollars; DEVELOPMENT
DRILLING = $20,000 in 1975 dollars; FACILITY CONSTRUCIION = $14,000 in 1975
do Ilars; PRODUCTION OPERATIONS = $15,5000 in 1975 dollars; ONSHORE FACILITY
2000 0 0 0 OP ERATIONS = $17,5000 in 1975 dollars; and for SUPPORT SERVICES throughout
the lifetime of the project = $15,5DO in 1975 dollars. Employment estimates
1,500 1,500 21.0 calculated from OCS Sale No. 35. Chapter 8.

458

FIGURE 1:
LEASE SALE #35, EMPLOYMENT AND INCOME ESTIMATIONS 1976-2000*

BEFORE ACTUAL LEASE SALE

Lease.Sale #35 Offering = approximately
as originally scheduled- .1.7 million acres

Lease Sale'#35 Offering = approximately
as finally scheduled: 1.2 million acres

LEASE SALE

Lease Sale #35 awarded: approximately
December 11, 1975 312,000 acres
56 tracts

EXPLORATION PHASE

.Variables** Estimates Projections

Tracts leased = 56 Employment = 8,200 man-y6ars
Wells per tract = 2 Income = $164.0 million
.Total wells. = 112 Time = 4-6 years
Wells per rig per yr. = 4
.Rig-years = 28
4-6 rigs
over 4-6 years

DEVELOPMENT PHASE

Platform Fabrication

Variables Estimates Projections

Total no. platforms = 10-20 Employment = 3,200 man-years
Platform fabrication = 25-33% in Income = $60.8 million
southern California Time = 5-8 years
I pl itform per year
Development Drilling SUPPORT SERVICES
Variables : Estimates Projections Projection
Total no. platform Employment = 7,500 man-years
=20 Employment = 7,200 man-years Income = $116.25 million
Rigs per platform = 1.5 Income = $144.0 million Time = 40 years
Rig yrs. per platform = 3 Time = 10 years
6 rigs
over 10 years

Onshore Facility Construction

Variables Estimates Projections

Plant size Employment = 1,500
Income = $21.0 million
Time = 6-10 years

PRODUCTION PHASE

Production Operations
VariablLs Estimates Projections
.Resource .6-2.2 billion Employment = 11,260 man-years TOTAL EMPLOYMENT
estimates**** bbls oil Income = $174.53 million 44,380
.8-4.0 trillion Time = 4b years man-years
cu. ft. gas TOTAL INCOME
$777.26 million
Onshore Facility Operation over lifetime
Variables Estimates Projections of project
Th roughput approximately Employment = 5,520 man-years
100,000 B/D Income = $96.68 million
I0OWcf/D ave. Time = 40 years

*All employment and income estimates pertain to both direct and indirect calculations. Employment projec-
are in man-years summed over the entire phase. Income projections are in 1975 dollars.

**All physical variable estima tes are based on assumptions in OCS Sale No. 35.

***Forecasts for onshore facilities depend on available surplus capacity of existing facilities and the
effects of consolidation policies encouraged by state and local regulatoryagencies.

****From resource estimates by OCS Task Force.

SUB-REGIONAL EMPLOYMENT AND INCOME ESTIMATES

Almost all of the effects resulting from Lease Sale #35 will probably be felt
in Ventura, Los Angeles, and Orange Counties. Because the populations of Los
Angeles and Orange Counties are larger than that of Ventura County, this report
treats Orange and Los Angeles Counties.as one region and Ventura County as another.
The difficulties involved in forecasting whether@staging operations would take
place in the Los Angeles/Long Beach area or tn Huntington Beach also made this
necessary. Furthermore, due to the relative importance of the oil and gas indus-
tries to Ventura County, it was assumed that the same percentage of key workers
would be imported into both this region and into the larger Los Angeles/Orange
area. The ratios for local-versus-imported workers implicit in Table I will thus
be utilized for the sub-regional, or county-level, analyses as well.

Table 3 presents monthly employment and quarterly wage statistics for the oil
and gas industries for each of the three counties. Although oil and gas related
employment and income in the Los Angeles area is roughly 7 times that in Ventura
County, the percentage of total oil and gas industry wages is about 2% for the
Ventura area versus approximately .5% for either Los Angeles or Orange County.
About 60% of all California wage income derived from-the oil and gas industries
occurs in the three counties, and Los Angeles-County alone possessed 45% of the
State's total in the period from July to September, 1974.

TABLE 3:
MONTHLY EMPLOYMENT AND QUARTERLY WAGES FOR ALL INDUSTRIES AND OIL AND GAS
EXTRACTIVE INDUSTRIES IN CALIFORNIA AND VENTURA, LOS ANGELES, AND ORANGE COUNTIES
(JULY - SEPTEMBER 1974)
California Ventura Los Angeles Orange

All Industries

Number of
Employees:
July 8,008,676 .121,299 3,021,166. 566,580
August. 8,078,460 121,555 3,012,278 551,631
September 8,254,770 124,269 3,058,952 548,591

Total
Quarterly Wages $20,054,609,462 $274,293,778 $7,823,996,485 $1,315,103,965

Oil & Gas
Extractive
Industries

Number of
Employees:
July 23,767 1,627 9,731 2,254
August 23,806 1,582 9,760 2,181
September 23,763 1,615 9,749 2,171

Total
Quarterly Wages $84,996,038 $5,557,041 $38,171,163 $7,052',081

From State of California, Employment Development Department, California Employ@
ment and Payrolls July-September 1974, March 10, 1976.

460

In calculating the employment derived from the Santa Rosa-Cortez Ridge
North, Santa Rosa-Cortez Ridge South, Santa Barbara island, and the San Pedro
Bay tract regions, the following assumptions have been made:

Phase Operations Base or Product Disposition Area

Santa Rosa Santa Rosa Santa San Pedro
Cortez-North Cortez-South Barbara Is. Bay

Exploration PH LA/LB/HB LA/LB/HB LA/LB/HB

Development PH LA/LB/HB LA/LB/MB LA/LB/HB

Production PH LA/LB/HB LA/LB/HB LA/LB/HB

Onshore Facility PH ..PH PH LA/LB/HB
Operations

Given these considerations, it is necessary to derive a relative weighting
scheme for the four regional tract areas in order to project scenarios. This was
achieved by using the number of wells drilled for each area-as a common deno-
minator for deriving relative employment estimates. The following numbers of
wells are likely to.be drilled in each area, and although these estimates are
based on the best currently available information, it is important to recognize
that they are not rigid proje ctions:

Tract Areas Anticipated Wells Percent of Total

San Pedro 30 27
Santa Rosa Cortez-North 22 20
Santa Rosa Cortez-South 54 48
Santa Barbara Islands 6 05

Total 112

Given the results obtained above, and the information contained in the previous
table, it is assumed throughout the rest of our calculations that about 20% of the
employment from exploration, development, production, and service operations
will take place in Ventura County, as well as approximately 33% of construction and
about 73% of onshore facility employment. It is assUmed that all employment derived
Jrom platform fabrication will occur in the Los Angeles-Long Beach area. It is
further expected that about 80% of all regional staging employment for exploration,
development, and production and 27% of onshore facility employment will occur in
the Los Angeles-Long Beach area.

These results appear in Tables 4 and 5 presenting total employment (local
and imported) and total income by OCS phase for each region. Average yearly
totals for employment and income are also calculated. Table 6 presents a break-
down, by year, of the combined yearly average estimates derived from Tables 4
and 5 giving the estimates for yearly employment and income for each region over
the first ten years of OCS development for Lease Sale #35.

Port Hueneme is abbreviated by PH, and Los Angeles-Long Beach-Huntington Beach
by LA/LB/HB 461

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Average Yearly
CD 4. Income
4@ 0% CO CD

These estimates are used in later sections of this report to arrive at
projections for peak years of employment and income, as well as the average
values over the first ten years of development. While estimates of total
years of employment, either by phase or by the project as a whole, have been
presented in Figure 1, as well as in Tables 2, 4 and 5, it should be emphasized
that it is very easy to overstate the effects of long-term projects like the
one under consideration here by focusing on total rather than on yearly employ-
ment. In order to avoid this statistical exaggeration, the employment and
income effects for the first ten years of the project are represented (Table 6)
as average annual figures for each year, and it is these estimates which will
be used as a base in conducting the economic analyses that follow.

TABLE 6:
AVERAGE YEARLY EMPLOYMENT AND INCOME EFFECTS FOR VENTURA, ORANGE, AND LOS ANGELES
COUNTIES OVER FIRST TEN YEARS OF PROJECT

VENTURA ORANGE - LOS ANGELES
Year Average Total Average Local Average Imported Average Total Average Total Average Local Average Imported Average Total Income
Employment Employment Employment Income Employment Employment Employment Employment
(in man-years) (in millions of$) (in man-years) (in millions of $)

1 265 200 65 $5.03 1060 803 257 $20.12
2 265 200 65 $5.03 1060 803 257 $20.12
3 396 200 116 $7.65 1904 1443 461 $36.67
4 452 336 116 $8.43 2014 1553 461 $38.23
5 751 635 116 $13.45 2514 2053 461 $46.12
6 751 635 116 $13.45 2514 2053 461 $46.12
7 751 635 116 $13.45 2514 2053 461 $46.12
8 751 635 116 $13.45 2514 2053 461 $46.12
9 546 490 56 $9.35 1694 1473 221 $29.72
10 546 490 56 $9.35 1694 1472 221 $29.72

463

Thus it will be noted that the estimates shown in Table 6 ard relatively in-
significant. We have arbitrarily (Table 6-A) multiplied these estimates
by three in order to highlight the fact that even three times the estimates
(referred to as upper bound) are relatively small. The following range of figures
for total employment (local and imported) and total income, based on calculating
a ten-year average for the estimates listed in Table 6, will be used in later
sections of this report.

TABLE 6-A

Ventura Los Angeles/Orange

.Average Income Impact/year
(in millions of dollars)

Estimate $9.9 $35.9
3 X Fstimate 29.7 107.7

Average Number of Local
Employees/year

Estimate 95 370
3 X Estimate 285 1,110

Average Number of Local
Employees/year

Estimate 454 1,576
3 X Estimate 1,362 4,728

ECONOM IC IMPACTS

I N D U C E D E MPLOYMLNT AND INCOME EFFECTS

To this point in our discussion we have been concerned with regional first-
round OCS-related employment and income. Now our focus shifts to the regional ef-
fects from second-round employment and income, also known as induced impacts
since they Fe-sult -from the first round. The relationship between these two
cateqories may be described as follows: round one ends with completion
of the development phase, when production commences. Round two consists of the
production of goods and services to replace the commodities consumed in round one.
Because some of the income earned in round one is saved, round two effects are
smaller than round one.

We assume that all employment, and hence income, resulting from OCS-related
projects is new employment. This implies that all project-related workers in round
one and round two are either unemployed at the start of the project or are bid
away from other jobs.* It is possible that some of the goods and services indus-
tries will not require new workers to meet second round demand. In that case, our
estimates will be liberal, because income would have been earned even if Lease Sale
#35 had not taken place.**

If workers are bid away from other current employment, such a situation could pre-
cipitate a slight regional wage increase. However, this type of effect is not
relevant for conducting an analysis of first-order impacts, as presented here.
**See Onshore Impact of Offshore Southern California OGS Sale No. 35, p. VIII-28.
464

We use a region.al multiplier, described in,Appendix Z, to calculate how
.many-second-round jobs are created by first-round spending. For the Los Angeles/
Orange area the multiplier equals 1.0 and for Ventura County it equals .5. This
means that for every job created by OCS'development in the Los Angeles/Orange
area, one new job will be created by induced spending. Similarly, for every
worker employed during the first -round of spending in the Ventura area, .5
workers will be needed for the@second round.

Table 7 shows total domestic, or local employment, stemming from the first.
and second rounds of OCS devel'opment. We estimate average, new yearly employment
to equal 729 for Ventura County and .3,522 for Los Angeles/Orange Counties. We
have again arbitrarily multiplied -these derived estimates by three to indicate
that even at the statistically-opti,mal (and unrealistic) upper bound, the effects
remain of slight significance to the regional economics.

TABLE 7:
AVERAGE NEW YEARLY DOMESTIC EMPLOYMENT AND INCOME
FROM LEASE SALE #35

Ventura Los Angeles/Orange
(M=.5)

Estimate 3.,X Estimate Estimate 3 X Estimate

Average Yearly 729 2,186 3,522 10,566
Domestic Employment

Average Yearly $12.3 $37.0 $58.4 $175.2
Domestic Income Million Milli-on Million Million

Table 7 presents Average Yearly Domestic Employment (AYDE) and-Average Yearly
Domestic Income (AYDI) resulting from first- and second-round local spending. The
.relevant equations are:

AYDE = StM(SH)
AYDI = $17,500 (s +,M(S + .5T))
s = local employment
t = importediemployment-
M = multiplier
= average yearly wage (calculated from Table 1)

Imported employment (t) is multiplied by 1.5 to reflect the assumption that only
50% of the imported workers are expected to reside near the development areas.
First- and second-round yearly income,averages $12.3 million for Ventura and
.$58.4 million for Los Angeles/Ventura.. These estimates are also arbitrarily
multipl.ied by three to present upper bounds.

465

P RICE. IMPACTS

In estimating the price effects from Lease Sale #35, housing and consumer
durables@provide sensitive indicators because they represent a large share of
family budgets and because a small increase in the price-of these items may
involve substantial sums of money. In the short run, the supply of consumer
durables.and housing is fixed, therefore.increases in demand will result in
increased price. In the long run, increases in demand will be.balanced by
increases in-supply, and no long-run price increases are created by demand
alone.

To arrive at an estimate of the increase in demand from OCS employment we
assume that it is proportional to the percent @hange in income. Then we use
elasticity measures to translate the demand increases into price increases..*

In order to estimate the.short-run price effects, it was first necessary
to estimate total income,.by county, in-1975 dollars. This was done by quadrupling
first-quarter figures for-wage income for@1975. 8/ For our purposes, there was no.
loss in reliability in utilizing thi.s simp.lification.**- Next, new income-was
calculated from Table 6,.by averagi,ng income-effect.per year over the first ten
years of the project, in 1975 dollars.***

The following table presents estimates for change in demand (x),,which is-
equal to-new income divided by total income:- .

County Income(1975) New Income Estimate X
(Millions of Dollars@

Ventura 1,119.5 9.9 .0088
LA/Orange 389091.7. 35.9 .0009

The table, below, shows the change in demand.at the upper bound.

County- Income(1975 3x New Income Estimate. X

Ventura 1,119.5 29.7 .0265
LA/Orange. 38,091.7 107.7 .0028

The price elasticity (e) of demand measures the sensitivity of the quantity of
a particular-commodity demanded to a change in its pri;ce., It is more precisely
defined as the percentage change in quantity.demanded.resulting from.a 11 change
in price of the given commodity,-i.e., e =-d(Q)Q = d(Q)P
d FP TP d(P)Q
Here l/e is weighted by x, or-the increase.in demand generated by OCS Lease.
Sale #35, in.order-to tstimate the resulting percentage-change in price.-

Until data for the entire 1975 period are made available, the most precise
estimate of 1975-income-can-be made.-by comparing the quarterly figures for 1974,
and then.projecting any seasonal-vartations to the 1975 January-March data.

***Unlike the previous section of this report,..new income here is taken to.equal
total local-plus imported income, even though.this results in an overstatement-
of the estimated effectsi

466

By applying elastilcity estimates to the change. in demand, we obtain per-
centage-increases in-prices for the selected goods. Table 8 shows.price increases
for houses, kitchen and household appliances, new cars,. and net purchases of used
cars. The short-run price elasticity estimates for the last two.of these.commodity
categories were-taken from Consumer Demand in the United States, 1929-1970. 9
Because it is very difficult to estimate a value for e (elasticity of demand)
which pertains to new housing purchases, the short-run price.elasticity-for
housing was roughly approximated at .5.*

TABLE 8:
ESTIMATED PRICE EFFECTS IN VENTURA COUNTY
AND-LOS ANGELES AND ORANGE COUNTIES
.FROM LEASE SALE #35, FOR SELECTED COMMODITIES

Ventura Los Angeles/Orange

Commodity Elasticity Estimate 3 X Estimate. Estimate .3 X Estimate.

Housing -.5000 .018 .053 .002 .006-

Consumer
Durables

Kitchen and
Household Appliances.-.6253 .014 .042 .001 .004

New Cars and Pur-
chases'of Used Cars -.9578 .009 .028 .00.1 .003

It can be.seen from7abl.e 7 that the short-run effects for Ventura County are.
much larger than those for Los Angeles and Orange Counties, where all calculated price
effects for both estimated and upper-bound1ncome levels are statisti'cally.,significant.
In Ventura County, where the-@estimated price effects equal an increase of 5.3% at the
most for new housing, it should:be-recogniz.ed that this estimate is the least re-
liable of the-three commodity categories. The price.effects on kitchen.and other
household appliances, and on automomobile purchases,.a.re expected to increase 4.2%
at most. Both of the,preceding figures are based%on the upper-bound estimate-for
new income. For the lower estimates, based on the expected income effects,.the
corresponding price i-ncreases in Wntura County are calculated@at 1.8% for new
housing, and 1.4% for auto purchases, kitchen and other household appliances.:

Because the price effects from increased housilng demand may be:the most.
significant of the economic consequences.of-Lease.Sale #35,-current housing and
population figures are presented in:Tables 9 and,10 in.,order to gain a more precise
understanding of [email protected]. Tabl-e 9 demon,strates that for Ventura,

This figure was derived by Using, as-a lower bound, the value.for e -.1874,
which pertains to "Other Housing" in Consumer Demand in.the@United States, 1929--
1970, and which comprises-transient hotels, tourist cabins, clubs, schoo.1s,-a
institutions (types.of housing commonly occupied by I the h ighly mobile' workers
typically employed in the exploration and deve-lopment.phases) and the,value of
e = -.6523,.for kitchen and other houshold appliances,'as an.upper bound.

31-76658 467

Los Angeles and Orange Counties in the years 1970-1975 ' added housing units have
increased at a faster rate than population. Although annual housi.ng production
in the future is expetted to be lower than the peak years"of the 1960s, the rate
of projected housing growth is still anticipated to.be larger than that of
population. It is assumed that over the 1970-1990 period,-population will increase
by 21.9%'in the large region comprising Ventura, Los Angeles, Orange, Imperial ,
Riverside, and San Bernardino Counties, while housing units are expected to
increase by 32.9%. 10/

In the Ventura County area, the expected, average yearly number of new dwelling
units required by employment from Lease Sale #35, is assumed to vary roughly
between 50 and 150.* The current vacancy rates shown in Table 10 for the three
prime areas of Ventura, Port Hueneme, and Oxnard can easily support this expected
influx of new employees and their families to Ventura County, even when taking into
account the current 1970-1975 baseline rate of yearly population growth of 2.85%,
and thecurrent annual increase in new housing units of 5.70% for the county as a
whole, as presented in Table 9.

TABLE 9:
HOUSING AND PUPULATION FIGURES
VENTURA, LOS ANGELES AND ORANGE COUNTIES, AS OF 1975**

Ventura Los Angeles Orange

Total Housing 144,108 2,695,401 607,631
Units 1975

Added Housing 31,979 157,638 144,828
Units 1970-75

Simple.Annual 5.7% 1.24% 6.26%
Housing Growth
-Rate-1970-75

Total Population .432,407 7,020,772 1,684,500
1975

Added Population 53,910 - 17,992 264,114
1970-1975

Simple Annual 2.85% - .05% 3.72%
Population Growth
Rate 1970-75

These figures are calculated-by multiplying the average number of imported
workers over the first ten years of,the project, calculated from Table 12, by
the re1ocation factor of 50%, -presented in OCS Sale No. 35. Also, see the
followtng section on public services.

SCAG-76 Growth Forecast Policy, Development Guide, Southern California
Association of Governments, Los Angeles, CA, January 1976.

468

TABLE 10:
TOTAL HOUSING UNITS AND VACANCY RATES IN VENTURA COUNTY
FOR CITIES WITH A POPULATION OF AT LEAST 10,000*

Housing Units Vacancy Rate

Ventura County 148,327 ----
Ventura 25,688 5.29%
Port Hueneme 5,968 11.6%
Oxnard 29,921 7.7%
Camarillo 8,361 4.64%
Santa Paula 6,350 3.8%
Thousand Oaks 19,167 5.9%
Simi Valley 19,061 2.4%

CONCLUSIONS@

Approximately 777 million dollars and 44,380 man-years of employment will
be created in a 20-year period in the southern California region that includes
Los Angeles/Orange and Ventura Counties. On the average, this means about 2200
jobs and 38.8 million dollars of income per year. In percentage terms, OCS
activities will.contribute less than 1% per year to southern California's
economy.

Throughout the entire region about 4,250 non-project related jobs would
also.be created. Of these non-project related jobs, 83% would occur in Los
Angeles/Orange, the remainder in Ventura. Further, we could find no evidence that
the project will bring about a sustained increase in the price of durable consumer
goods or housing. Two other points-bear repeating: first, cumulative effects
resulting from future lease sales may reverse these findings, and second, the
numerical value of our estimates is not exact. We are convinced, however, that
changes in economic activity brought about by Lease Sale #35 will be inconse-
quential.

From "Semi-Annual Population Estimates, January 1976", Ventura County
Planning Department.

469

PUBLI C SERVICES

Lease Sale #35 will result in a net inmigration of population into Los
Angeles, Orange, and Ventura Counties. This net inmigration, consisting pri-
marily of petroleum-related employees and their families, will expand and
diminish as specific development phases are begun and others are completed.

PUBLIC SECTOR INVESTMENT

An increase in the population of a community imposes a cost to that
community. The cost will take one of two forms: (1) an increase in local
expenditures to construct, operate, and maintain new facilities; or, (2) a
reduction in quality of service because of the increased number of users of an
existing facility -- e.g., school systems, waste water treatment system, or
police and fire departments.

Investment decisions by the public sector are primarily a function of demo-
graphic factors. The community, in attempting to make the most efficient use of
each expenditure, will seek to roject, as accurately as possible, the growth in
relevant demographic variables Tg., population, age distribution) in order to
prepare for the public services needed to sustain the community by ensuring that
new or existing services be capable of serving the future influx of people. The
measure of this ability is called excess capability. Local communities, par-
ticularly those smaller in size, are unable to finance internal capital require-
ments brought about by the need to expand services. Hence, they are particularly
sensitive to cyclical costs of debt issuance. In many instances, communities
will aggregate a number of small issuances and go to the capital market with one
major issuance in an effort to reap the savings of lower debt costs. As a
result, precisely calculating the size of needed capital facilities is critical.

In specifying the amount of excess capacity to be built into a public service
system, it is implicit that such systems will service up to some upper bound or
threshold level of population or economic activity. Beyond that level service
quality will deteriorate or new capital will be required. As the influx of new
employees proceeds, it is possible that these thresholds could be exceeded,
requiring local governments to accelerate debt issuance schedules, to purchase
such high relative-cost variables as fuel oil, or to allow growth to assume
patterns of land use inferior to those possible under more controlled conditions.

We may find that a specific lease sale will lead to effects which take a
community very close to, yet not beyond, a critical growth threshold. Ignoring
costs associated with environmental deterioration, such a project will probably
bring in, on balance, a net benefit to the community. If, however, another lease
sale occurs shortly thereafter, the threshold may be exceeded, with the probable
result that social costs would exceed benefits. Hence, any-one lease sale by
itself may not constitute a problem to local governments, but it is the potential
accumulation of them, with attendant effects, that must be planned for over the
long run.

470

FOCUS ON VENTURA COUNTY. While the major onshore effects from Lease Sale #35
will be felt in Los Angeles, Orange, and Ventura Counties, the only perceptible
impact on public services will occur in Ventura County. The reasoning behind this
assumption is apparent when the reader takes note of the infinitesimally small
proportion of imported residents in the Orange and Los Angeles demographic bases.

METHOD OF ASSESSING EFFECTS ON PUBLIC SERVICES

The method employed to assess the effects on public services is closely
related to the assessment of employment and price effects.

Assuming prices as given, we measurethe increase in total demand by the
ratio: # of new residents / # of total residents = X. Alternatively, new demand
may be measured by new income / total income. A choice between the two would
depend on, which is more appropriate to the public service being assessed.

The next step is to measure current excess capacity of public service
systems (Y). If X>Y, then new.capacity, measured by (X=Y) times total supply,
is required. If, however, Y>X, then the threshold is not met and no perceptible
opportunity costs are borne by the community.

Measures of supply vary, depending upon which type of-service is being
assessed. When measuring*excess capacity in wastewater treatment systems, the
appropriate unit of measure is million gall.ons per day. Excess capacity in
primary and secondary school systems is calculated on the basis of pupil/teacher
and pupil/classroom ratios, while capacity in highway systems is most effectively
assessed using some measure of congestion. Police and Fire Department capacity
is much more difficult to specify, though a commonly accepted criterion is 1.5
policemen per thousand population and 2.5 3.0 minute response time to any fire
alarm.

It is important to emphasize that we assume no change in the effective
price of a public service and that people demand a constant proportion of their
income be spent on public services.

In order to demonstrate a range of potential effects, we derive an estimate for
X (increase in total demand) and also an upper bound equal to three times this
estimate. The estimate is derived by multiplying the ave'ra e number of imported
employees per year over the first ten years of the project ?1976-1985), as taken from
Table 6, times average density per dwelling unit in Ventura County (3.0). ll/
This result is then multiplied by .5, the relocation factor assumed throu-gFout.
rhe value of X will be identical for each service impact assessment in Ventura
County. The estimate And upper bound values are:

95 3.0 .50
432,400* 0.00033 = X 1 = estimate

285 ' 3.0 .50
432,400. 0.00084 = X 2 = upper bound.
These results are noteworthy because the values for X are not significantly
different from zero.

See footnote 15.

471

If we were, moreover, to assert that a 1% increase in demand for public
services as measured by X was the lower, threshold of significance, it would
require an inmigration of approximately 28 times the size we project for Lease
Sale #35 to reach that level.

It is only valid to conclude at this point that we are not able to measure
percentage excess capacities within the Xl or X2 value ranges of zero. We
will, however, proceed with calculations of excess supply function values of Y
so as to demonstrate the relative growth-supporting capability of Ventura
County public services, should ultimate cumulative effects approach the range
of significance of X.

POLICE AND FIRE

The impact of Lease Sale #35 upon public expenditures for, and quality of,
police and fire service to communities within the study area will not be dis-
cernible.

Public Interest Economics-West conducted telephone interviews with the
Ventura City, Oxnard, and Port Hueneme Police Departments as well as the County
of Ventura Sheriff's Department. Each indicated that a net population growth in
the 500-to-2,000 range would not affect current capital facilities planning. A
very marginal increase in the police and fire force may*result if new residents
settle in the same locale or in remote unincorporated areas.

The Police Departments of both Oxnard and Port Hueneme indicated that they
currently employ 1.2 to 1.35 policemen per thousand population. This is marginally
below the statewide average of 1.55.* The average is even lower for smaller-sized
communities.

Telephone interviews were conducted with representatives of Ventura and Oxnard
Fire Departments as well as California State Firemen's Association. Each indicated
that an influx of the range we specified would not perceptibly affect quality or
timeliness of response to alarms. A response time of 21-2 minutes is the stated
objective of urban departments throughout the state and this is more a function of
building type and distribution than minor increases in population.

SCHOOLS

In order to obtain data for assessing the current capacity of Ventura County
Schools, Public Interest Economics-West conducted interviews with officials of
relevant school districts. Two measures were used for calculating capacity, and
Table 11 shows the results of each.

The first measure is the result of a comparison of current enrollment to
state and/or locally-calculated capacity. The state capacity estimate is based
on square footage area in schools. The local capacity figure is derived
empirically by the school district. The net result, presented in column 3,
reflects the degree of excess supply (positive value), or the degree of over-
crowding (negative value).

Our second measure is the ratio of pupils to teachers. A statewide average
is then presented for the elementary level (such an average is not calculated
for secondary schools at the state level) and a reasonable estimate of current
capital capacity is inferred therefrom.

Reported to PIE-West by the Peace Officers Research Association of California,
November I , 1976. 472

In addition to the empirical measures presented in Table 11, we have included
a brief series of comments, Table 12, which further illustrates the current
capacity of each district.

TABLE,11:
SELECTED VENTURA COUNTY.SCHOOL DISTRICTS

SURPLUS
ENROLLMENT CAPACITY- PUPILS/
SCHOOL DISTRICT CAPACITY FALL 1976 ENROLLMENT TEACHER'

CONEJO'VALLEY UNIFIED
Kindergarten-6 10,905 10,776 129 -30
7-8 3,2-76 3,588 -312 30
9-12 5,300 6,241 -941 31

HUENEME ELEMENTARY
Kindergarten-8 6,750 6,400 350
7,100* 700 28

OCEAN VIEW ELEMENTARY
Kindergarten-8 2,250 2,100 150 24 (K-5)
28.95(K)
29.04(1-3)

OXNARD ELEMENTARY -
Kindergarten-8 10,050 9,824 -226 33.95(4-6)
24.61(7-8)

PLEASANT VALLEY ELEMENTARY
Kindergarten-8. 5,600 5,400 200 27.8

'OXNARD UNION HIGH,
9-12 10,500, 11,281 -781 27.0(74/75)

SANTA PAULA ELEMENTARY'
Kindergarten@-8 3,502 2,978 524 25.6

SANTA PAULA UNION HIGH
9-12 2,000 1,30u 700 27-3(75-76)

SIMI VALLEY UNIFIED
Kindergarten-6 13,373* 12,022 1,351 31
7-9 5,806* 5,846 -40 32
10-12 5,103* 4,754 349 31.5
4,300 4,754 -454

VENTURA UNIFIED
Ki ndergarten-6 8,777
7-12 7,898

STATE OF CALIFORNIA
1-3 27.2/classroom
4-8 27.1
9-12 State does not calculate
an average

Figures calculated by the California State Department of Education. Conversations
with District Superintendents suggest these figures may be unreasonably.high.-
473

TABLE 12:
COMMENTS OF SCHOOL DISTRICT REPRESENTATIVES

Conejo Valley - Phyllis Schatz of the Planning Office: All schools are using portables;
a new high school-is under construction and will open for the school year 1978-79.

Hueneme Elementary - Charles Slaughter, Superintendent: Operating within capacity;
part of.an.expanding residential area; own a site that will probably be built on
in six or seven years.

Ocean View Elementary - Robert D. Allen, Superintendent: Within capacity; expect to
grow slowly, 35 students per year, unless there are zoning changes. If Pdtit
housing tract is approved, it would result in an influx of 100 students and that
number could be handled.

Oxnard Elementary - Norman Brekke, Superintendent: Crowded: running a twelve month
year. Two recent bond issues have failed and the District is applying for funds
from the Public Work Capital Development and Investment Act of 1976.
Oxnard Unton High - Andy McEuen, Superintendent: Over capacity; voters-turned down
bonds in 1975 and 1976. Foresees double session and extended days. Projected
high school enrollment in 1981 of 13,755 based on current elementary attendance
and no move-ins.

Pleasant Valley Elementary - Charles Honn, Superintendent: Will reach capacity
in a couple of years; have $300,000 remaining from last bond issue; may go to 12
month year.

Santa Paula Elementary - Dr. De La Rosa, Superintendent: Well within capacity; net
23 empty classrooms; expect to close a school.

Santa Paula Union High - Secretary to the Superintendent: Well within capacity; net
increase of students over the last ten years approximately 100.

Simi Valley Unified - Edmund Richard, Director, School Facilities, Robert Allert,
Property.Manager:.Elementary well within limits; 7-12 overcrowded, but that will
ease in six years with declining enrollment in the elementary schools.

Ventura Unified - John C. Wolfe, Associate Superintendent: Considers the district
.to be at capacity; building anew elementary school; expect to build another high
school within 5-10 years. No extended days or double sessions at present; one
school on a 12-month year.

Although our results may be interpreted in a variety of ways, we feel they demon-
strate several key points. Fi-rst, that in the event of a relatively minor increasse
in resident population, significant costs may be experienced by Simi Valley, Conejo
Valley, and Oxnard Union High because they-have no excess capacity. Further, that
the marginal or incremental costs may,be quite high when compared to each
community's current tax base.

A more thorough.evaluation of the probable patterns of res 'idential.preference
by imported OCS employees would be necessary in order to refine our estimates. Local
planning officials, presumably having conducted such studies, will be more fully
equipped to assess the extent of the above@noted incremental costs upon their own
-community.

474

WASTEWATER TREATMENT

Interviews.were conducted wit h officials of the Ventura County Regional
Sanitation District, officials of local City Engineering Departments, and staff
of the Ventura County Planning Department to determine the excess supply in the
@Ventura County wastewater treatment system.

Pursuant to Section 4700.00 of the California Health and Safety Code, the
Ventura County Regional Sanitation District is currently implementi,ng a county-wide
plan, the "Sewerage Master Plan" of 1975. Under this plan, the District is acquiring
all local plants in the County and, upon completion, will manage all plants as an
integrated wastewater treatment system.

In Table 13, we present data on present use, present capacity, percentage
excess capacity, and projected capacity for the year 2000, as calculated by the
Regional District, for each facility in the county.

Assuming 100 gallons per.capita per day, there exists excess capacity to
handle over 300,000 new residents in Ventura County. It is not probable, however,
that new'residents would make housing location decisions so as to maximize use of
existing capacity. As a result, existing excess capacity for new residents
county wide is probably much less on the order of 150,000 to 200,000.

TABLE 13: -
WASTEWATER TREATMENT PLANT CAPACITY
VENTURA COUNTY

FACILITY PRESENT USE (1976) PRESENT CAPACITY (1976). FUTURE CAPACITY (2000)
Equivalent Equivalent Excess Excess% Equivalent
MGD* Population MGD** Population Capacity(MGD) Capacity MGD Population

Camarillo 2.70 27,000 4.75 47,500 2.05 43.2 8.00 80,000
Filmore .67 6,700 0.75 7,500 .08 10.7 1.30 13,000
Oak View 1.65 @16,500 1.50 15,000 -.15- -10.0 3.00 30,000
Oxnard 10.00 100,000 25.00 250,000 15.00 60.0 37.50 375,000
Piru .09 . 900 .20, 2,000 . 1 55.0 .40 4,000
Santa Paula 2.00 20,000 2.50 25,000 .@O 20.0 3.50 35,000
Simi Valley 5.50 55,000 7.00 70,000 1.50 21.4 14.00 140',000
Thousand Oaks 5.75 57,500 @10.00 100,000 4.25 42.5 20.00 200,000
Ventura 7.00 70,000 14.00 140,000 7.00 50.0 14.00 140,000
Port Hueneme 3.75 37,5000 6.00 60,000 2.25 37.5 (no change)
to be consolidated
Moorpark .40 4,000 1.00 10,000 .60 60.0 to be consolidated
Montalvo .12 1,200 0.25 2,500 .13 52.0 to be consolidated
Saticoy .10 1,000 0.86 8,600 .76 88.4 to be consolidated

TOTAL 39.73 453,800 73.81 738,100 34.08 102.1 1,021,000

Millions of gallons daily
The most commonly accepted standard for usage is 100 gallons per.capita day. Hence, the gallons were
converted to equivalent population. Using this technique, non-residential usage is subsumed in equivalent
residential usage.
SUUKUL@.: Ventura County Regional Sanitation District, "Sewerage Master Plan," February 1975.
Interviews with City, County and District Officials.

475

In those areas with the highest growth rates -- Simi Valley,
Thousand Oaks, Oxnard -- there is substantial excess capacity. Only one community,
Oak View, is at or in excess of its capacity, and-a doubling of that facility's
capacity is currently planned.

There is no evidence to suggest from these data that growth thresholds.will be
exceeded as a result of Lease Sale #35 activity in Ventura County. In the event
that subsequent lease.sales significantly affect county demographic patterns of the
future, thresholds may be approached; yet given the small relative cost share borne
by localitiesin treatment plant-construction (,121-, percent) it does not appear to be
an area-of major concern.

Tables 14 and 15 present a summary of selected public-sector effects
including school enrollment, housing, population, and per capita local government
expenditures for each of the.study areas.

TABLE 14:
IMPORTED EMPLOYMENT, ORANGE AND LOS ANGELES COUNTIES

(A) (B) (C) (D) W-
Average Increase Increase Local Government
Imported in in School Expenditure
Year Employees Population Enrollment Housing ($000)

1976 257 694 139 129 618
1977 257 694 139 129 1108
1978 461 1245 249 231 1108
1979 461 1245" 249 231 1108
1980 461 1245 249 231 1108
1981 461 1245 249 231 1108
1982 461 1245 249 231 1108
1983 461 1245 249 231 1108
1983 461 1245 249 231 1108
1984 221 597 119 ill. 531
1985 221 597 119 ill 531

NOTE: Numbers in the columns were derived as follows! (A) is given from Table 6;
(A) x 2.7 (B); (B) x.20 = (C); (A) x .5 = (D); (B) x $890 (E). The
multiplier 2.7 refers to persons per dwelling unit as estimated in.SCAG-76
Growth Forecast Policy (So,uthern California Association of Governments,los
Angeles; January,,1976). The multiplier .20 is drawn from "Active Enroll-
ment in California-Elementary and Secondary Public Schools, Fall, 1975"
(California State Department of Education,.1974). The multiplier .5 is a
residential relocation factor. The multiplier.$890 is calculated from,-
a) Financial-Transactions Concerning, Cities of California; b) Financial
Transactions@Concerning Counties of California; c) Financial Transactions
Concerning-School Districts of-California; and, d) Financia:1 Transactions
Concerning.Special Districts in California, Office of the Controller, for

476

TABLE 15:
IMPORTED EMPLOYMENT IMPACT, VENTURA COUNTY

(A) (B) (C) (D) (E)
Average No. Increase Increase Local Government
Imported in School Expenditures
Year Employees Population Enrollment Housing ($000)

1976 65 195 49 33 138
1977 65 195' 49 33 138
1978 116 348 87 58 246
1979 116 348 87 58 246
1980 116 348, 87 58 246
.1981 116 348 87 58 246
1982 116 348 87 58 246
1983 116 348 87 58 256
1984 56 168 42 28 119
1985 56 168 42 28 119

NOTE: Numbers in columns were derived as follows: (A) is given from Table 6;
(A) x 3.0 (B); (B) x .25.= (0: (A) x .5 = (D); 2nd (B) x $707 = (E).
The.multiplier 3.0 refers to persons per -dwelling united as estimated in
SCAG-76 Growth Forecast Policy, (Southern California Ass'ociation of
Governments, Los Angeles: January 1976). The multiplier .25 is drawn
from "Active Enrollment in California Elementary and Secondary Public
Schools, Fall 1975" (California State Department of Education, 1974).
The multiplier .5-is a residential relocation factor. The multiplier
$707 is calculated from: a) Financial Transactions Concerning Cities of
California; b) Financial Transactions Concerning Counties of California;
c) Financial Transactions Con.cerning School Districts of California; and,
d) Financial Transactions Concerning Special Districts in California,
Office of the Controller, for 1974-1975.

T A X E S A N D T R A N S F E R S

Substantial flows of money result from Outer Continental Shelf oil and
gas development. These flows arise in four forms:
1. increase in personal disposable income of residents within the study
area(discussed earlier in the Economic Impacts Section);
2. changes in natural gas prices and gas supplies brought about by
extraction of the resource;
3. the study area's share of national economic rent deriving from bonus and
royalty payments; and,
4. state and local tax revenues less incremental costs of public services.

PETROLEUM PRODUCT PRICES

It is a well documented fact that savings associated with Outer Continental
Shelf crude production will not be directly passed to the consumer. 12/ Even .
assuming a competitive domestic in.dustry, free of direct price regul-aTion, the price
of OCS crude will not fall below the landed price of OPEC crude unless total domestic
production throughout the U.S. would flood all foreign oil off the U.S. market. As
a result, there is.no consumer surplus in oil price to be derived from Southern
California OCS production even if there are very high levels of production.

There is much current discussion of the impact of an anticipated glut of crude
on*the West Coast by 1979 when Alaskan crude will be reaching peak flow. It
is important to emphasize that although supplies in excess of local' demand may pass
through southern California en route to Texas for refining, they will not affect the
477.

market price. Put simply, no domestic producer is willing to sell oil for
less than the landed price of foreign. Regional income deriving from OCS gas
,extraction, however, may increase.

REGIONAL SHARE OF NATIONAL RENT

Oil and gas operations on the Outer Continental Shelf are not currently
taxable by state and local governments. The federal government has jurisdiction
over OCS operations, and firms acquire rights to develop OCS lease tracts from
the federal government in exchange for bonus and royalty payments.

A successful bidder for a tract receives a five-year lease, granting exclusive
right to explore the tract and produce as much oil and gas as possible for as long
as mineral production continues. The lease fixes the amount of annual rent ($3.00
per acre, due annually until production is initiated) and the amount of royalty
(a percentage of the market value of the output). The royalty may be no less than
12-12% and has been generally set at 16 2/3% for OCS development. The payments are
intended to reflect a fair return to the public for the market value of the
resource.

OCS bonus and royalty charges bring in significant revenues to the federal
government. As reflected in Table 16, total royalty payments from 1970-1976 exceed
$2.5 billion, with a per annum average of $429 million. As a frame of reference,
Louisiana Coast operations paid $226 million in royalties and rents during 1970
while producing 338 million barrels. If, as projected, Lease Sale #35 peak pro-
duction levels reach 75-100 million barrels per year, federal royalty and bonus
revenues will reach $80 million per annum.

. The benefits to residents of the study area from those federal receipts will
arise either in the form of reduced federal income taxes or increased quantity
and/or quality of federally financed public services.

TABLE 16:
FEDERAL BONUS AND ROYALTY RECEIPTS FROM
OUTER CONTINENTAL SHELF LANDS FOR 1970-1976
(Millions of dollars)

Bonus Royalty Total

1970, 944.8 283.5 1,228.3
1971 96.3 350.0 446.3
1972 2,251.3 363.6 2,614.9
1973 3, 91.0 401.1 3,492.1
1974 5,021.1 560.3 5,581.4
1975 1,088.2 615.5 1,703.7
1976 2,242.9 N.A. ---

TOTAL 14,735.9 2,574.0 15,066.7
Source: United States Department of the Interior

478

STATE AND LOCAL TAXES

The principal sources of OCS-related revenues to state and local governments
are personal income taxes, property taxes, and sales taxes. Additional sources
such as licenses, fees, and user charges are not sufficiently significant to
include in the present analysis.

INDIVIDUAL INCOME TAXES. California's individual income tax will yield
moderate sums over the life of the project. As shown in Table 17, the peak year
total for both direct and indirect related wages and salaries will be $1.16
million. This is an upper-bound estimate in view of its implicit assumption that
all OCS employment is new and that all employees will file California as their
place of residence. Local units of government in California are not constitu-
tionally empowered to impose income taxes.. As a result, local residents will
be limited to benefits derived from increased state income tax revenues either
lower relative tax burdens or higher quality state services.

TABLE 17:
STATE INDIVIDUAL INCOME TAXES GENERATED BY
LEASE SALE NO. 35 - RELATED WAGES AND SALARIES
(millions of 1975 dollars)

TOTAL TOTAL INUIVIDUAL INCOME
YEAR EMPLOYMENT INCOME TAXES GENERATED

1976 976 18.17 .345
1977 1850 35.65 .677
1978 2450 47.45 .902
1979 2825 54.40 1.033
1980 3220 61.39 1.166
1981' 2566 47.75 .907
1982 2278 41.99 .798
1983 2540 45.41 .863
1984 2400 42.15 .800
1985 2500 43.80 .832
1986 2300 39.80 .756
1987 1925 32.85 .624
1988 1650 28.00 .532
1989 1250 20.00 .380

1995 1250 20.00 .380
199b 1230 19.69 .374

2000 1230 1.9.69 .374

TOTAL 44,380 777.30 14.77

Data derived by multiplying total employment per year by average income per
employee per year ($17,500) times the 1975 effective tax rate (.19) (State
of California, Department of Finance).

479

The income tax data were derived by multiplying total employment per year
by the average income per employee per year ($17,500) by the 1975 effective tax
rate for that income bracket (.'019).

SALES TAXES. Each of the counties in the study area is-subject to 6% sales
tax imposed by the State. The distribution of the revenues derived from the tax
is as follows:
4 3/4 % State of California general revenues
1 % local general purpose revenues
4 % local mass transportation
The 6 % rate has not changed since April 1974, at which time the state general
revenue share increased from 3 3/4 % to 4' 3/4 % of taxable sales.

Table 18 presents estimates of anticipated sales tax revenues derived from
wages and salaries from Lease Sale #35. This table, as well as the property tax
tables which follow, present estimates based on the average total income and employees
per year. These average estimates are derived by summing the average total income
columns of Ventura, Orange, and Los Angeles Counties in Table 6. We have limited
our analysis to ten years since estimates beyond that period, using average data,
are on very weak ground.

TABLE 18:
SALES TAX REVENUES GENERATED BY OCS #35 RELATED WAGES AND SALARIES
IN LOS ANGELES, ORANGE AND VENTURA COUNTIES
(millions of 1975 dollars)

TOTAL AVERAGE DISPOSABLE RETAIL TAXABLE SALES TAX
YEAR INCOME INCOME SALES SALES REVENUES

1976 25.15 21.38 16.70 12.52 .7513
1977 25.15 21.38 16.70 12.52 .7513
1978 44.32 37.67 29.42 22.07 1.324
1979 46.66 39.66 3U.98 23.23 1.394
1980 59.57 50.63 39.55 29.66 1.780
1981 59.57 50.63 39.55 29.66 1.780
1892 59.57 50.63 39.55 29.66 1.780
1983 59.57 50.63 39.55 29 .66 1.780
1984 39.07 33.21 25-94 19.45 1.167
1985 39.07 33.21 25.94 19.45 1.167

480

The above sales tax data were derived by multiplying average total income for all
counties in the study area by .85, the ratio of disposable income to average total
.income, to obtain personal disposable income. This- result is then multiplied by
78.1, the average ratio of retail sales to wage and salary income-in California
from 1970 to 1975. This figure is then multiplied by .75, the value of-the.ratio
of total- taxable sales/total retail sales in California. This figure is then
multiplied by .06, the sales tax in each of the counties in the study area.

.Regarding the ratio of taxable sales/retail sales, note should be,taken of the
fact that the value of the ratio varies from county to county, because the composi-
tion-of retail sales varies from county to county. In aggregating the three
counties we used the unweighted average of the 1975 figures:
Los Angeles .738
Ventura .680 X = .75
Orange .736

-PROPERTY TAXES, Property taxes are the principal source of income-to local
governments. In 1975, over 85% of local-revenues in California were drawn from
property, with school districts being:most heavily reliant upon them. Property
tax revenues resulting from OCS development will be drawn from two sources:

1. residential property tax revenues resulting from the importation of
OCS employees; and,
2. commercial and i.ndus trial tax revenues resulting from the construction
and operation of onshore OCS related facilities.

In Table 19, we present estimates of annual property tax revenues resulting
from the-inmigration of new,employees. Continuing our upper-bound approach, we have
assumed that each new employee will form one new dwelling unit.
The data in Table 19 are derived by multiplying new employees by a@erage annual
income ($17,500), and multiplying this result by 14 in order to arrive at total net
valuation, assuming each employee is willing to sperid 25% of his income
jor housing. We then multiply this result by .25 (to obtain the State mandated
assessed value) and finally, multiply this result by the relevant tax rates in the
counties.

In addition to property tax revenues derived from newly developed housing for
relocated OCS employees, revenues will a-lso result from the construction of onshore
facilities related to.offshore development activities. Planning for onshore capital
facilAties, in the absence of certainty.pertaining to the actual volume of reserves,
is tenuous. We are able, however, to estimate an approximate range of capital
.value associated with facilities anticipated for the Port Hueneme and Long
.Beach areas.

481

TABLE 19:
RESIDENTIAL PROPERTY TAX REVENUES GENERATED AS A RESULT OF LEASE SALE #35
LOS ANGELES, ORANGE AND VENTURA COUNTIES
(millions of 1975 dollars)

Average No. Average Average New
Imported Total Increase Property
Employees- Income of.- Residential Assess Tax
Year Relocating/year. Imported Employees Valuation Value Receipts
Ventura . ,
1976 33 .57 2.28 .57 .063
1977 33 .57 2.28 .57 .063
1978 58 1.02 4.06. 1.02 .113
1979 58 1.U2 4.06 1.02 .113
1980 58 1.02 4.06 - 1 U2, .113
1981 58 1.02 4.06 1.02 .113
1982 58 1.02 4.06 1.02 .113
1983 - 58 1.02 4.06 1.02. .113
1984 28 .49 1.96 49 .055
1985 28 .49 1.96 .49 .055
.9T-4

Orange & Los Angeles
1976 129 2.25 9.00 2.25 .252
1977 129 2.25 9.00 2.25. .252
1978 231 4,04 16.14 4.04 .452
1979: 231 4.04 16.14 4.04 _452
1980 .231 4.04 16.14 4.04 .452
1881 231.. 4.04 16.14, 4.04 A52
1982 231 4.04 16.14 4.04 A52
1983 231 4.04 16.14 4.04 A52
1984 ill 1.94 7.74 1.94 .217
19,85 ill 1.94 7.74' 1.94 .217
3.650

Data for Table 19 were derived by multiplying.average-imported employees/year,
from Table *.6 times 150s- the accepted relocation factor,:times the projected
average annual income of $17,500 to get total. income. Assuming the average
family consumes housing valued at approximately four times current income*
this will result in total.valuation of-new housing of total income of relo-
cated employees times four.: This result is then multiplied by .25, the
statewide assessment ratio.for real-estate.. Finally., this result-is
multiplied by the.1975'property*tax rate (per thousand valuation) for each
county. Ventura is 11.11, while for Orange and Los Angeles counties the
average taken is 11.21.

Given the urban family budget studies of the Bureau of Labor Statistics, a.
$17,50b income earner will spend $4,375 annually for housing.services. Using
our rule of thumb, a $17,500 income.earner--will purchase a $70,000 home.
This implies a 6.25% internal rate of return, which we find to-be reasonable.

482

In Table 20, we present capital requirements-for facilities that can reasonably
be expected to be constructed in each study area. If we assume for each location
the construction of one permanent service.base, one gas processing plant, one surge
tank farm, and two marine terminals, as well as one platform fabrication yard
somewhere within the aggregate study area, we can project a.range of capital valuation
for the entire area from $130 to $160 million. In discussing these facilities it
is i.mportAnt to point out the speculative nature ofthe assumption of a platform
fabrication yard in the study area. None has been proposed as of this date.

Assuming -a 25% assessed valuation and an average tax rate of $12.00 per
hundred assessed value., the onshore facilities will yield between-$3.88 and $4.80
million per annum in property taxes to the aggregate study area. To demonstrate
the scale of these additions to the taxable base, it is 'noteworthy that the $160
million high estimate, if located totally within Ventura, would constitute only
.022% of that county's taxable base.

TABLE 20:
ONSHORE FACILITIES RELATEDTO OFFSHORE OIL AND GAS DEVELOPMENT
(1976 Dollars) . -

Permanent Service Base

1. Breakwater 1,125,000
2. Reclamation 200,000
3. Dredging 200,000
4. Road Access 50,000
5. Berths for Vessels 1,125,OOU,
TOTAL $2,700,000

Marine Terminal $50,000,000
Onshore Tank Farm** $20,380,000
Gas Processing Plant*** $26,000-000
Platform Fabrication Yard $30-60'91000'000

Fixed sh-oreside terminal. designed for 2509000 barrels' per day,. and storage of
1 million barrels.
For detail of-typical cost breakdown, see Table 21.
***A 300 million cubic ft/day capacity. plant.
Source: Onshore Facilities Related to Offshore Oil and Gas Development Factbook,
New England River-Basins Commission, 1976.

32-76658 483

TABLE 21:
I*NVESTMENT COST ESTIMATES FOR ONSHORE TANK FARMS

Shoreside Terminal Mid-Depth Terminal

Total Storage Capacity l"OOO'OOO 2,000,000
Crude Tank Configuration 4 x 250,000 2 x 250,000
3 x 500,000

Land Development 340 740
Storage Tanks 3,300 6,370
Tank Farm Piping 480 660
Piping to Refinery 12,290 14,260
Pumping Station 400 1,030
Drainage & Wastewater Treatment 200 220
Fire Protection 300 350
Electrical 300 400
Buildings & Miscellaneous 600 650
Subtotal 18,210 24,690
Mobilization/Demobilizatian 1,790 2,510
Total Construction Cost 20,000 27,200

In thousands of 1974 dollars (all costs 25% because-of non-specificity
of site).

SOURCE: Arthur D. Little, Inc., and Frederic R. Harris, Inc., Petroleum
Development in New England, Vol. 11, 1975. p. IV-13.

EQUITY'CONSIDERATIONS

With continued and increased levels of oil and gas development activity,
cumulative effects in many forms may arise. Regional income and employment will
rise, local public revenues will increase, costs of government operation will
grow, and environmental damage will occur. From the perspective of residents
and property owners within the study area, equity considerations arise -- namely,
to what degree do the benefits of increased regional income and public revenue
exceed public service and environmental costs? And, to the degree they
fall short of doing so, at what level and in what form are residents compensated?

The Federal leasing system of bonus and royalty payments described previously
is intended as a vehicle to provide the public with a fair return in exchange for
the granting of sole resource development rights to a private firm. There is ex-
tensive debate in the literature, however, as to the adequacy of this system of
compensation, and substantial evi-dence suggests that competition is currently less
than optimal as a result. j3/

Examined independently, Lease Sale #35 does not appear to warrant additional
compensation to residents on the basis of work conducted thus far, since the cost
increases in public service will be minimal. However, environmental effects have not
yet been measured, and it is possible that they may tip the balance for
Lease Sale #35 so that costs exceed benefits. Further, in an aggressive leasing
program',compensation may play.a significant role.
The'literature on equity strongly suggests that compensation is necessary where
environmental damage is incurred by a specific population and that such compensation
for a public or depletable externality does not impose market distortion.'14/

484

In the case of oil and gas development, the most efficient form of compensation
to the public may be a tax on the profits of production. Although the law is some-
what unclear on the feasibility of legally instituting such a tax, the return to the
public might be very high. Given the very high market value of the extracted
resource and the fact that such a tax would impose no misallocations on the market,
it is eligible for thorough consideration. -The major pitfall of pursuing such a
tax is the difficulty in identifying profits.

Alternatives exist, such as increasing existing royalty payments requiring
the posting of performance bonds by private firms, or the setting aside of specific
funds in escrow. In any case, the objective must be to provide those affected by
the development.with compensation equ-ivalent to the discounted present value of
net costs incurred. To date, no uniformly recognized measure for quantifying these
costs has been developed, and indeed they are frequently of a non-monetary nature.

CONCLUSION

The development of Outer Continental Shelf oil and gas off the coast-of
southern California will not substantially alter the structural relationships or
the overall volume of economic activities in the affected onshore communities.
However, the impact on small and medium-size communities may, in the instance of
a protracted and productive leasing program, be discernible. The effect upon
larger communities, unless highly abnormal labor supply or housing preference
patterns are evident, will not be perceptible.

Over the economi:c life of the project, 44,380 man-years of employment and
$777 million in income will be produced within the three-county study area. Thes-e
effects will be spread over 40 ye-ars, with 1980 reflecting peak levels of activity.
Of the major phases involved in the development operation, the most labor-intensive
and that which yields the highest annual income is exploratory drilling. During
the peak year, exploratory activity will create 1550 jobs within the study area
of which 1070 will be local employment. In terms of total man-hours over the life
of the project, production operations yield the largest sum, comprising 25% of the
total. Other development activities which constitute major percentages are support
services and development drilling, comprising respectively 17% and 16% of total
employment,

Of the two sub-areas examined, Ventura County, on average, will experience
approximately 20% of the new employment and associated income, with the Orange/Los
Angeles Counties sub-area receiving the remainder. During the peak year of the
project, average total employment associated with Lease Sale #35 will reach 751
in Ventura County and 2,514 in Orange/Los Angeles. These employment levels will
produce income flows of $13.45 and $46.12 million respectively. The levels of
employment imported into the study area, approximately 464 workers per year on
average, will be relatively inconsequential. As a result, the net effect upon
public service within the affected communities will be very minor.

In Ventura County, the results of Lease Sale #35 fail to exceed specific
growth thresholds that would require increased public service cost to

485

local governments or reduced service quality. Several high-growth areas such as
Simi Valley, Thousand Oaks, and Oxnard are, however, nearing capacity levels in
schools, and subsequent lease sales with attendant immigration will
conceivably necessitate increased local expenditures.

As a result of new imported demand and a relatively fixed supply of housing
and consumer durables, short-run price effects will be felt in the study area. In
Los Angeles and Orange Counties, these effects will be very small. In Ventura County,
however, a short run increase of 2% may be anticipated for housing, while prices
of consumer durables, inclusive of kitchen appliances and automobiles, may increase
1.5%.

OUS development will result in increased housing development, higher retail
sales, and higher general income levels in the affected counties. These higher
levels of economic activity will result in increased levels of public revenues --
principally income, property, and sales tax revenues.

Including residential development as well as OCS onshore facilities construction,
we anticipate increased annual revenues during peak production years of $1.52 million
in Ventura County and $4.92 million in the Orange/ Los Angeles Counties area. Over
the 1976-1985 period, cumulative increases in property tax revenues for the three
counties will be approximately $530 million. This total represents approximately
.04 % of anticipated revenues over the same ten year period.

The increase in state income tax revenues resulting from OCS activity will
be relatively minor. During the peak year, net income will approach $1.16 million
and a ten-year cumulative increase of $14.77 million may be anticipated. Sales tax
deriving from increased levels of retail sales activity will peak 'at $1.78 million,
and over the 1976-198b period will yield a total of $13.67 million. The peak year
flows of $1.16 million for income and $1.78 for sales.represent less than .1 % of
the aggregate yearly amount for the State. Peak year incremental flows of new tax
money to the State of California will approximate $2.6 million while the local peak
will exceed $6.0 million.

C U M U L A T I V E. E F F E C T S

As noted above, these regional economic effects will not alter structu ral
relationships or significantly vary levels of economic activity. We hasten to
emphasize, however, that effects deriving from a number of lease sales may accumu-
late and impose more substantial consequences. Such may result from the specific
timing of the projects themselves or the scale of staggered development activity.
Local officials should be very attentive to these effects on the horizon and be
sensitive to their relationship to growth thresholds. In this respect, Lease
Sale #48 and #53 should be thoroughly examined for such effects as soon as adequate
estimates of reserves are published. Using the method described in this chapter,
local planners should be capable of deriving incremental cost and revenue
estimates for each sale.

E N V I R 0 N M E N T A L C 0 N S I D E R A T 1 0 N S

One area requiring further research is the economic assessment of environ-
mental impacts resulting from OCS Lease Sale #35. This analysis would be important
in the event that environmental effects resulting from other regional lease sales
are to be evaluated. Cumulative impacts stemming from Lease Sale #35 and #48
as well as those derived from the current development program within the Santa
Barbara Channel, may be sipnificant. The movement of Alaskan crude along the
Southern California Goast will affect the environment.

486

In order to properly evaluate any possible environmental effects from Lease
Sale #35, the following kinds of analyses should.be-conducted:

1. an evaluation of the probable physical effects in the event of.an oil
spill, using current data on probability. estimates and resulting
clean-up costs; and,
2. a presentation of baseline water and air quality data, forthe regions
unde,r consideration, as well as estimates of percentage increases in
pollutant load resulting from Lease Sale #35.

Given these considerations, the following kinds of effects should be.assessed:

1. changes in the pattern of recreational usage resulting from the above air
and water quality baseline changes, with an appropriate assessment of the
costs borne by both consumers and resource owners;
2. costs incurred to both fishing and agriculture, with consideration,given
to the specific potential for crop damage and loss of fisheries;
3. changes in property assessments; and
4. evaluation of the effects of increased pollution on the health of
individuals residing and/or working in the region.

When conducting this analysis, it is important to note that percentage increases
in water and air pollution may be-a.poor measure of such environmental effects,
since the first units of pollution may not be noticeable, while later units may
become very significant. Thus, cumulative effects resultingfrom many lease sales
could become very large. Furthermore, it is very difficult to compare pollution
costs to other economic costs. Finally, since pollution reduces the quality of
life for all individuals in the affected area, there is no dilution-effect when
considering the effects upon a large versus small population.

Again, changes in traffic congestion and the landscape are not measured
accurately by the use of percentages. Furthermore, if congestion is measured
by travel-time, this type of effect can rise very rapidly as capacity is neared.
In Los Angeles and Orange Counties, and perhaps in Ventura County, the imminence
of these kinds of effects may not be obvious due to current levels. However, in
the event that the cumulative environmental impacts of several lease sa-les are
assessed, it is likely that many of the previously cited impacts may be large,
and it is entirely possible that they may outweigh any easily measurable
economic benefits to the region.

487

FOOTNOTES

1. U.S. Department of Commerce, Survey of Current Business, LVI (August 1976),
pp. 26-27.

2. Governor's Office of Planning and Research, State of California, Onshore
Impact of Offshore Southern California OCS Sale #35 (January 1976), pp. VIII-1 - 79.

3. Ibid., p. VIII-74.

4. Ibid., p. VIII-22.

5. Ibid., p. VIII-72.

6. Council on Environmental Quality, OCS Oil and Gas -- An Environmental
Assessment, IV (April 1974).

7. Bureau of Land Management, U.S. Department of the Interior, Final Environ-
mental Statement, Proposed 1975 OCS Oil and Gas General Lease Offshore Southern
California (OCS Sale #35), 1975.

8. State of California, Employment Development Department, California Empl-oy-
ment and Payrolls, January-March 1975, August 10, 1976.

9. H. S. Houthakker and Leslie D. Taylor, Consumer Demand in the United States,
1929-1970 (Cambridge: Harvard University Press), 1966.

10. Southern California Association of Governments, SCAG-76 Growth Forecast
Policy (Los Angeles)-, January 1976.

11. Ibid.

-12. J. W. Devanney, III, Georges Bank Petroleum and New England R20onal Income
(Cambridge: MIT Sea Grant Program), 1976.

13. For a cross-section of current thought on this topic, the following
articles are recommended:

H. E. Leland, Optimal Risk Sharing and the Leasing of Natural Resources,
with Application to Oil and Gas Leasing on the OCS, Working Paper #38,
Institute of Business and Economic Research, Berkeley,.California.

H. E. Leland, R. B. Norgaard, and S. R. Peason, Economic Analysis of
OCS Leasing Policies, National Science Foundation, Office of Energy
Research and Development Policy, September, 1974.

488

W. J. Mead, P. E. Sorenson, and R. 0. Jones, "An Economic Analysis of
the Performance of the Cash Bonus Bid Leasing System for OCS Oil and
Gas Resources in the Gulf of Mexico," paper presented at the Southern
Economic Association Annual Meeting, Atl.anta, Georgia, November 1976.

14. W. J. Baumol and W. E. Oates, with contributions by V. M. Vawa and
D. Bradford, The Theory of Environmental Policy: Externalities, Public Outlays,
and the.Quality of,Life-(Englewood Cliffs, New Jersey:..Prentice-Hall), 1975.

489

APPENDIX 1

C 0 N S I D E R A T 1 0 N S O.N U S I N G A N I N P U T - 0 U T P U T
M A T R I X T 0 A S S E S S R E G 1 0 N A L E C 0 N 0 M I C I M P A C T S

Throughout the period of our analysis, we have discussed with individuals,
departments, and agencies the merits of using an input/output matrix to assess
regional economic effects of OCS development. In most instances, the sDecific
model discussed has been the Curtis-Harris model which the Department of the
Interior has used extensively to measure the economic effects of enerqy-related
developments. The following discussion represents our thoughts concerning the
merit of using an input/output matrix for this purpose, as well as some of the
analytical weaknesses.

An input/output (1/0) matrix is one way to portray the relationships between
different sectors once a study region has been defined. The rows of an 1/0 matrix
demonstrate how the output of one sector is distributed among the other sectors,
and the columns characterize the flow of inputs into one sector from other sectors.
Such a portrayal is not an analytical model but a framework for collecting and
integrating the movement between economic sectors. Under particular assumptions
about production and markets, the matrix does, however, serve as an analytical tool,
and the Curtis-Harris model is an example of a matrix used as such. As an analyt-
ical tool, the 1/0 matrix has been limited because of the cost of collecting data.
In their present state of development, 1/0 matrices can have from 200 to 600 rows
and/or columns and require over 1,000 rbservations for each study reqion each year.
It would cost approximately $160,000, plus admi.nistrative expenses, to develop
data for one year.

Given that OCS effects will occur over a period of years, and'that to make
accurate forecasts of the future, several years of historical data are required,
we can estimate that an 1/0 matrix would cost about $500,000.

Further, transforming the 1/0 matrix from a framework to an analYtical tool
requires making assumptions which may or may not frustrate the goals of the study.
As an analytical tool, the 1/0 matrix produces reliable forecasts in some, but not
all, circumstances.

ASSUMPTIONS

In order to use the data of an 1/0 matrix analytically, the first assumption
is that inputs used to make outputs combine in fixed oroport4ons. This allows
the analyst to state, for example, that if wages were 10% of total costs before
an increase in production, then wages are 10% of total costs after such an increase.
Since this assumption would require frequent revision in order to reflect the tech-
nological change highly characteristic of the oil industry, the reliability of 1/0
matrix forecasts about the effects of increasing production would be difficult to
maintain.

A second assumption must be that there is no joint production, since the 1/0
matrix is not structured to cope with it. Joint production occurs if two or more
outputs can be produced in varying proportions by a single production process. To
the extent that OCS drilling produces both oil and gas, then I/0-based forecasts about
the changes in the distribution channels are frustrated. For example, let us assume
that in one day of drilling x bbl of oil and/or y cubic feet of gas can be recovered.

490

Since different processing and transportation facilities are required for these
different commodities, and since x bbl of oil has a different monetary value than
y cubic feet of gas, 1/0 forecasts will be unreliable.

.A third assumption about the production process is that constant returns to
scale prevail. This assumption means that if we wish to transport twice as many
barrels of oil to an onshore orocessing facility, then we must double all trans-
portation inputs. It is well known, however, that pipel'ines are subject to strong
economies of scale. Thus, an 1/0 forecast would tend to overstate the effect of
increasing the rate of resource extraction.

In addition to the above assumptions about technoloqy, it is also necessary
to make assumptions about the market characteristics through which the goods and
services of a region or industry pass. This is necessitated because intersectoral
flows are expressed best in terms of dollars rather than ph.ysical units. If markets
are competitive, then prices adequately measure the value of goods and services.
1/0 models, howevei, will fail to give accurate forecasts if inflation has unevenly
distorted money prices over time, or if there is a significant amount of non-market
transactions, or a significant amount of transactions in markets that are not
competitive.

The first of these problems -- inflation distortion -- can be overcome by using
@index numbers. The second is not easily remedied: non-market transactions and/or
transactions in non-comDetitive markets must be included by imputation and adjust-
ments. This not only makes the 1/0 forecast less dependable but can undermine its
objecti vi ty.

Other assumptions include the assertion that sectoral sales are equal to sec-
toral payments. This not only assumes that inventory levels are constant but also
implies that a balance exists between development costs and production costs. A
specific problem here is the case of growing sectors, where the level,of capital
investment is greater than revenues produced during the observed time period.

A final valuation problem concerns the assumption that must be made about the
hard line of depreciation. Ideally, an 1/0 forec ast is the net of any capital
consumption allowance. Such an assumption, however, necessitates further assuming
a standard rate of depreciation which may or may not conform to industry expectation
and practice.

OTHER CONSIDERATIONS

As a general rule, the rigidities of the above assumptions are not so severe
as to preclude entirely the use of 1/0 forecasting. Nevertheless, it is our
opinion that the conclusions would be dependent on the assumptions to an excessive
degree because: (1) the oil industry is characterized by technological change;
(2) oil and gas are jointly produced; (3) pipelining is subject to economies of
scale; and, (4) the oil industry is vertically integrated, growing, and known to
experience rapid changes of inventory levels.

Furthermore, 1/0 models do not contain such policy variables as tax rates
and subsidies. If the ultimate objective of a study is to provide information on
which to base decisions, then the analysis should indicate not only potential
problem areas, but also should indicate which variables may be adjusted so that
a.particular problem.may be attenuated.

491

Finally, since 1/0 models explain and predict interactions betvieen.different
sectors in a region, information would have been generated that was not germane
to our purposes. Bluntly stated, expenditures would have been made for unnecessary
information.

492

APPENDIX 2

I N D U C E D E F F E C T S

For the purposes-of the present study, induced income and employment are
created by the spending and re-spending of OCS-related income in the study region.

-Measuring induced effects is complicated by three interrelated spending
patterns. First, not all OCS-related income will be spent; some will be saved.
Second, of the OCS-related income that is spent, some will be spent outside the
region. Finally, not all of the OCS-related income spent within the region wil-1
create more jobs. For convenience, we will represent the above considerations
symbolically:
C><"= savings rate

I CX = rate of consumption

= consumption outside region

= consumption inside region

= consumption that does not generate employment

= consumption that does generate employment

Next, a mathematical expression is formed that represents the interaction of
these variables. It is:

(Equation 1) M E 0

A numerical value for the multiplier can now be obtained if we can determine
values for 0<, /3 , and if . C>< , the savings rate, is a relatively constant
variable equal.to .1. This means that about ten cents of every additional dollar
received'is saved. Called a leakage, /@q indicates the oercentage of every dollar
spent that leaves the region. the forces that influence the rate of leakage relate
to the size of the region and the extent of industrialization. Large regions have
smaller leakage rates than,small, regions, and industrialized urban regions have
smaller leakage rates than rural regions.

Los Angeles and Orange Counties form a large and heavily industrial-ized region.
was assigned a value of .3. This means that 30 cents of every dollar spent
leaves the Los Angeles/Orange area. Since Ventura County is smaller and less indus-
trialized than Los Angeles/Orange, 15 was assigned a value of .5. @5 indicates
that portion of locally spent income which does.not create employment. One quite
')@ is to use the ratio Of imported employ-
reliable rule of thumb for estimating L
ment,to total employment. For the Los Angeles/Orange region, this results in a
value of .19. For Ventura County, where this ratio is not applicable, Y was
arbitrarily assigned a value of .30. Summarizing, the estimates for 0< 13 and 6
for the two regions are:

493

Ventura Los Angeles/Orange

C>/- .10 .10
13 .50 .30
.30 .19

Inserting these values into Equation I results in an employment multiplier
for Los Angeles/Orange equal to about 1 and, for Ventura, .5. It can be seen that
as either c-x , 13 , or @@ rise, the multiplier will @ecrease, and hence, so will
induced employment. It should also be emphasized that for relatively small regions,
such as Ventura County, both the rate of leakages and the rate of demand not satis-
fied by domestic employment should be relatively large.

The above multiplier estimates may be compared to those in Table A, presented
in OCS Sale #35. Since multiplier effects are shown in that table, the estimates
corresponding to our analysis are 2.0 for the Los Angeles and the Orange Counties
region, and 1.5 for the Ventura area. It can be seen that our estimates fall within
the lower range of the multiplier spectrum, and that we do not anticipate heavy in-
duced employment.

TABLE 1:
EXAMPLES OF PUBLISHED EMPLOYMENT MULTIPLIERS USED IN OCS STUDIES

SOURCE MULTIPLIER COMMENTS

1. BLM 1.6 Described as "hiqh" in relation
to peak employment

2. OCZM 1.68 Based on U.S. Chamber of Com-
merce multiplier

3. Woodw6rd-Clyde 1.8

4. Resources Planning
5. Urban Pathfinders
6. Dames & Moore 9-2
7. Curtis Harris

8. Ultrasystems 3.0. For Los Anqeles County,

9. Gulf South-Research 3.1

10. Ventura County
11. Allied Contractors 4.0 Offshore:onshore ratio
12. WOGA (H. Wright)
13. USGS 4.4 Jobs in Texas per crude-rel'ated
job

14. AFL-CIO, CIRB 6.8 Construction indsutry
15. Gulf South Research 8.2 Prepared for the Louisiana
Governor's Office

From: OCS Sale #35, Table II, p. VIII-32.
494

APPENDIX 3

E Q U A T 1 0 N S A N D V A R I A B L E S U S E D

Equations Variables

Induced Employment and Income Impact
= savings rate
(1-2) (1-B) (1-8) = leakages outside region
M= ------------------ = percentage of new domestic
(1-[1-2][1-B][1-8]) demand which will not be
satisfied by new domestic
employment

Price Impacts
Percent increase in prices = x/e x = new income
total income

e = elasticity of demand
or
-dQ/dP
Q/P

Public Services

Assess if x > y X = new residents
total residents
or x <y
y = % excess capacity

Taxes and Transfers

Calculated on basis of current income, sales, and property tax rates and property
assessment ratios.

495

'CHAPTER 19

FACILITIES PLANNING:
.EASING THE
OFFSHORE/ONSHORE BIND

A primary concern of planning foe offshore oil and gas 'in southern California
is the apparent proliferation of onshore facilities occuring as a result of .
increased OCS activity. In the Santa Barbara Channel area there are 14 offshore
platforms, 42 seafloor well completions and one manmade island; seven marine ter-
minals for transshipment of crude oil; more than fifteen operating treatment and
storage facilities; and, the necessary complement of crew staging and support
facilities, pipelines, and pump stations. l/ Estimates of additional facili'ties
required to.develop the Santa Barbara Channel indicate a potential for ten to
.21 new platforms and/or ocean floor production systems; one to five marine termin-
als; and one to five treatment and storage facilities. 2/ From the Long Beach
area through Newport Beach there are six offshore islands and two platforms, numer-
ous slant-drilled wells from shore, nine wharfside petroleum terminals and one
Inarine terminal, 11 operating treatment and storage facilities, and a wide variety
of offshore-related.industry.and support facilities. 3/ Should Sah-Pedro Bay -
federal leases be developed, two to nine platforms anU ten to 60 miles of pipeline
could be proposed for the Long Beach to Newport,Beach area. 4/ In addition, the
Outer Banks leases could include from two to 13 -new platforms and up to 270 miles
of offshore pipelines. 5/

Given current plans for Santa Barbara Channel, Lease Sale #35 and the proposed
OCS Lease Sale #48, the demands placed on existing facilities and the need,for new
faci-lities can only increase. Yet because of the many petroleum companies. involved,
the numerous separate fields that could be developed, and the complex of existing
facilities, there is great potential for unnecessary duplication. Planning.on an
area basis, by identifiable geographic entities, could avoid such duplication.

A common criticism of the OCS leasing process as practiced by the Department
of the Interior in the past has been that it.represents a "lease now, plan later"
philosophy. 6/ In fact, the.little planning that has occurred for offshore develop-
ment.has been on a well-by-well or platform-by-platform basis -- occasionally on a
field-by-field basis, but never for a larger area. What planning there has been
for onshore development has been accomplished as a stopgap reaction to development
.pressures from offshore. This piecemeal approach has resulted in the proliferation
of faciliti.es now evident along portions of the southern California coastline.
Consideration of both the onshore and offshore facility requirements for OCS
development over a larger area would lead to.the logical design and siting of
complete systems for producing, transporting, and processing crude oil and natural

497

gas, while simultaneously eliminating the unnecessary duplication. Systematic
planning for offshore and onshore development together, however, has been conspic-
uously absent in the offshore leasing and devel-opment process. Conflicts between
development requirements-of offshore operators and prerogatives of onshore decision-
makers have occurred as a result of this lack of planning, most notable being the
Exxon Santa Ynez Unit controversy (see Appendix,5). In the absence of future
planning, additional conflicts can be anticipated. In order to ease this offshore/
onshore bind., we advocate three principal concepts: lease-area planning, unitiza-
tion, and consolidation.

Lease-area planning as proposed here is a method for looking at.large OCS
areas with,diverse leaseholders but with certain, common development oppor-
tunities and constraints. Unitization is a process.whereby several leases
overlying one prospect are managed by a single operator or committee. Con-
solidation refers to the sharing of onshore facilities, or the concentration
of necessary OCS-related activities within a few selected areas.

Although the authority for area planning exists within the discretion of the
Department of ihe.Interior, it has. not been undertaken offshore of southern
California. 7/ Industry. has voluntarily resorted to unitization and consolidation
where there appeared a cl.ear private-sector economic advantage to such j'oint
undertakings. Where private-sector economic advantages may be lacking, the U.S.
Geological Survey has the authority to require unitization-when i.t is shown.to be
in the interests of conservation. 8/ California also believes that-the.consolida-
tion of onshore facilities may be Justified in the interests of conservation if
the "costs" of environmental degradation resulting from any unnecessary duplication
of facilities outweighs the- benefits of such duplication. 9/

Of course., the feasibility-of unitization or consolidation may be limited by
other considerations: for example, critical-concentrations of air pollutants, or
tanker traffic congestion caused by intensified-operations at certain locations,
could be reason for strategically locating several small onshore facilities instead
of one large one.. Similarly, the timing of se-parate.exploration, development, and
production schedules may be incompatible, effectively limiting the ability of
individual companies to unitize or consolidate. Nonetheless, by taking-careful
.stock of the opportunities for coordinated development as they are perceived now
and in the future,,wasteful duplication of oil and gas facilities can be avoided.

If the authority to require unitization-of federal leases lies.solely with
the USGS, why should California be concerned? The answer is simple: requirements
for onshore support services and processing-facilities are directly related to the
number of offshore operations. When offshore activities-are unitized, the oil and
gas produced can. more easily be linked to a few selected onshore sites.
It is crucial, then, for onshore. planners to be made aware of offshore plans and
activities, and to.participate in unitization decisions where appropriate'.

The question remaining is: under what circumstances should unitization or
consolidation be required as a matter of public policy when.voluntary efforts
(determined by private-sector economics) fail to achieve the desired results?

This chapter describes those circumstances and the principles for coordinating-
offshore and onshore development to ease the offshore/onshore bind.. The following.-
material,is divided into three secti-on.s discussing lease-area@planning, unitization,

498

and consolidation. These discussions provide guidance in- making the choices for
future OCS development presented in Chapter 21.

AREA PLANNING

Off southern California, leases have been sold in several geographica-lly
distinct areas: the Santa Barbara Channel, the three Outer Banks areas and San
Pedro Bay. Proposed Lease Sale #48 may offer new leases for sale adjacent to these
existing leased areas plus three new areas along the Orange and San Diego County
coastlines (hereafter referred to as the San Diego Coastline). The areas described
in this section are shown in Figure 1.

These areas are unique on several levels. Each area is known
to have several oil and gas prospects, with the exception of the Santa Barbara
Island offshore area.which only has one. Each area is the combination of many
leases held by many different companies (with the-exception of the Santa Barbara
Island offshore area again, which only has one leaseholder). If we assume oil and
gas are discovered and producible from one or more prospects in these areas, each
is also,unique from a development standpoint. Some-of the factors distinguishing
each area are distance from shore, available shoreside facilities, water depth,
potential geologic hazards, environmental risks, and resource-potential@

The number of separate producible prospects, the diversity of ownership, the
geographic considerations and the obstacles to'producing and-delivering oil and gas
present much the same challenges to each operatorwithin a given area; ' The develop-
ment options for each.operator.will also be similar because.'of the inherent con-
straints and opportunities of the.lease area. -Nonetheless, in the absence of clear
direction from the managers of the OCS, each lease area may be developed.in fragments
and with-duplication of essential facilities. The history of the Santa Barbara
Channel indicates the likelihood of this fragmentation and its resultant redundancy
in facilities. In the past, such redundancy has been caused by divergent develop-
ment schedules, or simply forproprietary:reasons. Regardless of the cause,
duplication has increased the total development.costs as well as the-risk of oil
spill accidents and the incidence of air pollution.

Fragmented development can also lead to losses in rec *overable resources. For
example discoveries in-the remote outer bank areas could be uneconomic to produce-
when co@sidered individually; but when.considered-together,, production may be
feasible.

Avoiding the potential duplication of essential facilities and-potential loss
.of recoverable resources is clearly,an objective of the Department of the Interior
under its charge to manage the OCS for the prevention of waste.and the conservation
of,natural re7sources. 10/ Ideally, Interior should evaluate-areas before they
are leased to determin@_how best they could be developed (if at all) in light of
environmental concerns,.economic considerations, and [email protected] Interior
should then establish specific guidelines for developing an area of.leases in a
timely and coordinated manner and these guidelines should be made a part of lease-
stipulations attached to sale of OCS tracts. rn practice, as for Lease Sale #35,
Interior performs aggregate studies.of the development potential of OCS tracts
in terms of estimations of numbers of facilities required, persons employed and

.33-76658 499

SANTA BARBARA Figure 1
--CHANNEL
Ro
Ro.
PLANNING A
0

Port
Huenerne
im

p, Santa Los Angeles
47 D- onica

I Manhattan
Beach
. . . SANTA F40SA
. . . . . . -CORTEZ NORT LE=h

Beach

0 A
TkEA a
. . . . . . . . . . OFF HCR. S

Ul
0
SAND

TAf

M.-

:0.00,

L-J

--T
kv
-h Nits

1@ 110 @5 WWTE@ ffT73
1,@ -kES
cl
@TPI SCALE@1,;16D"- DE-WWEIN@ETs
t@ G-

LLL-Li-Li

environmental impacts of typical offshore operations for the lease sale area taken
as a whole. ll/ This development potential and 'the projected impacts are based
on estimates of undiscovered resources thought to'be recoverable in the area.

The questionable value of Interior's reliance on resource estimates determined
from the extremely limited data available, in lieu of actual Ore-sale exploration,
is discussed in Chapters 13 and 14. The aggregate conclusions derived from
Interior's analysis of development potential unfortunately provide.no real insight
into how a leased area could or should be developed or, more fundamentally, whether
a given area should be offered for lease in the first place.

The alternative posed here, "lease-area planning," is intended to deal
rationally with distinct offshore areas having in common certain development
constraints and opportunities that will be faced byall operators in the area.
The purpose is not to create another level of OCS management. We intend to deal
specifically with the problems now facing the existing OCS leaseholders -- and the
p,rospective leaseholders,, should Lease Sale #48 be held -- and to avoid unnecessary
duplication or possible loss of valuable resources. The objectives of lease-area
planning, then, are to achieve the coordinated development of potential offshore
resources, to eliminate unnecessary duplication of essential facilities, and to
eliminate uncertainties of future development for each leased area. In a lease-
area plan, agencies required to approve permits for various phases of development
could define project-specific criteria and applicable regulations that would allow
timely project approval. The results of lease-area planning would include timing
parameters for exploration and development, requirements for unitization, and
clearly defined'transportation and processing options. Interior can still identify
area planning problems for existing as well as proposed lease-areas and develop
solutions for each area. In the following, planning considerations identified by
the OCS Project Staff for each ar@a are outlined as an initial step in such a
planninq process.

C 0 0 R D I N A T I N G D E V E L 0 P M E N T I N T H E
5 A N T A B A R B A R A C H A N N E L

The Santa Barbara Channel planning area is shown as Area 1 on Figure 1. Of
the 65 federal leases in the Channel, 41 are unitized into five units and the
remaining leases are divided roughly into eight smaller areas. Figure 1 shows the
Channel divided into two subareas for planning purposes. This separation is both
logical and functional; leases to tracts in the west end of the Channel are held
by the Exxon/Arco/Chevron consortium and are separated by deep water from the east
end, where ownership is mixed. A total of nine different operators can be antici-
pated in the Channel. These operators are shown on Figure 2. Figurp 3 shows
functional operating areas in the Channel, based on ownership and current unit
boundaries. A total of 14 separate areas are shown but it should be noted that
this number could be reduced if some of the non-unitized leased tracts were ever
to be subsumed by existing or future units. Table I summarizes the status and
ownership of each area identified in Figure 3.

To summarize, the Santa Ynez, Pitas Point, Santa Clara, and proposed Hueneme
Offshore Units.are currently unitized after commercial discoveries hao been credited
within their boundaries. Union and Sun.share a cooperative agreement for production
from the competitive Dos Cuadras field reservoir, while Phillips produces from the
federal portion of the Carpinteria Offshore field as a result of-a federal drainage

501

Jalary)

SANTA BARBARA
a iota J19L) 5
-E

N le

at il Pt Pt o tec
Santa arbara arpint r
. ......... .

i,Mon o:nt

S film
1. ,ON

(16;
H,,ri@ Pi
,Prince, I Fraser Pt Dlan)o Pt
SAN MIGUE
t Sennett ISLAND Pt Coche Pt San Ped
SAN
Sandy Pt I ?-A
CF?Uz
Pt
Skunk

si"
S4NN

@wen Pt,
list Pt
ROSA ISLAND 'r PT

Clu@ter Pt

outh Pt

OPERATORS:
SANTA BARBARA CHANNEL

1;19 Leased Area G Gulf Su Sun 10 3
A Arco M Mobil T Texaco +10
NORTH SCALE 1:
C Chevron Pa Pauley U Union April 1977 Cal
E Exxon P Phillips

Exxon-Las Flores
SANTA BARBARA

a iota 0gu 5 101
Arco-Ellwood
-N le
"192 t89.... 04! il Pt cole"'. Pt o ec C
arp
S nta arbara int r
194 190 1,4

1-0 182/ 181 180
84 183

NTA YNEZ (Exxon

Kee (F-xxon)

22"
232-,
SAN MIG
V P
178 177
223, 222 1 @2. 1. 1.
(Exxon)
... "WK:
222/223
17.4
Wee .............. ----------
X.,
SANTA CISA SANTA CRbZ
.e:!. 213 212
X
cin n) (Chevron)
xxo
q 69 V

167

F!asc, Pt Dii@lo PL

Coche Pt
0N.%. C.-tuirR.Lon P,
Pt Bennettg:;@@ San P
Cardwell PIL
SAIV
Sandy PT _rA
CRUZ %S
Skunk P,
A Mors Pi
ROSA ISLAND
0:- j@en Pr
St Pt.
Chiter Pt
X.M.: _X,

IJU i P' ee.*

UNITS OR OPERATING AGREEMENTS:
SANTA BARBARA CHANNEL

Existing Processing Plant: 10
10
Proposed 0 Existing NORTH SCA
Potential Proposed April 1977

Table 1

OPERATING AREAS: SANTA BARBARA CHANNEL, APRIL, 1977 1/
unit or Prod rction D t:kof Esti ted
Coo perative Working Owners Numbersof Effective Sta)u t_U, Pe PeakmRate Processing
"A reement Operator of Interest Lease Date Phase ate Production Of Production Plant Site
EXISTING

Carpinteria Phillips Cities Service 1 10127167 production June 1968 Aug. 1969 27,899 BOPD Phillips-LaConchita
Field (Houchin and Continental 18,773 MCFD
Hogan) Phillips

Dos Cuadras Union GTUM 1 05/06/68 production Feb. 1969 Aug. 1970 60,097 BOPD Mobil-Rincon
Field ("A" and "B") 32,458 MCFD
Sun Sun 1 08/21/69 production July 1970 July 1971 30,420 BOPD Mobil-Rincon
Hi1Ihouse) Marathon 20,797 MCFD via Union Platform
Superior AI.

Pitas Point Texaco GTUM 3 03/31/73 exploration 21
Unit (discovery
credited)

Oak Ridge Gulf GTUM 8@ 03/31/73 exploration 21
Unit

Santa Clara Chevron Chevron 8 03/30/73 development Sept. 1979 1982 or 38,000 BOPD
Unit Exxon 1983
Arco
Union

Santa Ynez Unit Exxon Exxon 17 11/12/70 development Apr. 1978 1983-1985 60,000 BOPD
Chevron (Hondo only) 28,000 MCFD
Shell

Hueneme Mobil Mobil 2 development 1979 1980 12,000 - 2/
Of fshore Union 15,000 BOPD

San Miguel Exxon Exxon 6 1977 exploration -
Chevron
Arco

PROPOSED

Santa Cruz Chevron Chevron 6;1 exploration
Exxon
Arco

POTENTIAL

OCS-P 171, 169 (?) Exxon 3 exploration
167 Chevron
Arco

Anacapa Exxon Exxon 2 exploration -
(OCS-P 198, 199)

OCS-P 0222 and Exxon Exxon 2 exploration -
0223

OCS-P 0232 and Exxon Exxon 2 exploration -
0238

OCS-P 0226 and Pauley Pauley 2 exploration -
0218 Ashland
Colorado
J. M. Huber
Husky
Kewanee
Midwest

REMAINING

OCS-P 173 Arco Arco 1
Chevron

l/ Notes for Table 1 are derived from: (a) Final Environmental Statement,
Oil and Gas Development in the Santa Barbara Channel .... March 4, 19763,
USGS; (b) Hillary Oden, Acting Conservation Manager, Western Region, USGS,
letter to Suzanne Reed, OPR, June 22, 1976; and (c) information communi-
cated by representatives of petroleum companies involved in the respective
areas to Allan Lind, OPR.
2/ Mobil-Rincon is the logical site for processing any new production from
the Pitas Point and Oak Ridge Units and the Hueneme Offshore field because
the operators and owners of interest in these areas also own interest in
the Mobil-Rincon plant.
3/ Chevron considers the existing Mobil-Rincon facility or the Chevron-
Carpinteria.facility as equally viable options for processing new produc-
tion from the Santa Clara Unit. The same options could be considered by
Chevron if the proposed Santa Cruz Unit should prove productive.
4/ Las Flores Canyon has been approved by State and most local agencies as
the appropriate'location for a major new processing plant to be constructed.
Exxon, however, is currently developing an offshore floating processing
plant in lieu of this site. 504

sale. Of the 14 existing, proposed, and potential units or field operations, the
Exxon/Chevron/Arco 4@oup would be the operator of eight, the Gulf/Texaco/Union/
Mobil (GTUM group would control four, and Phillips and Pauley would each operate
one. 12/ These operating groups are described below.

The major issues to be-addressed..in planning for the Channel are the trans-
portation of crude oil (tankers vs. pipelines), the.consolidation of onshore
facilities, with the concomitant removal of oil and obsolete onshore facilities,
and the systematic exploration and development-of the Channel. In order to-deal
effectively with these issues, all levels of.government and industry.will have to
work together towards coordinating the timing, location, and scale of offshore
and onshore development. 13/ We recommend,that such a planning effort be carried
out as a part of the environmental impact statement now being prepared by the
Bureau of Land Management for Lease Sale #48.

EXXON/CHEVRON/ARCO

These three companies formed a consortium for bidding in the 1968 lease sale.
Between them they-acquired 49 of the 71 leases sold. They currently control 47 of
the 65 active leases. At least one of these three companies is represented in ten
of the 14 operating areas in.the Channel, and between them they operate eight.
They are not included in the Union/Sun operation of the Dos Cuadras fi-eld, the
Phillips operation of the Carpinteria field, the Mobil operation of the Hueneme
Offshore field, or the Pauley leases. Arco participates in three of the operating
areas but is not an operator in the federal portion of thethannel. Chevron-is
the operator of the Santa Clara Unit and the.-designated operator of the proposed
Santa Cruz unit,, both in the eastern end of the Channel (area 1B on Figure 1).
Operating these large units, Chevron could play an important role in shaping
future development for that area of the Channel. Exxon is a designated operator
in the west end of the Channel (area 1A on-Figure 1) of the Santa Ynez Unit and
the San Miguel Unit. Exxon's three pairs of tracts in the eastern block of leases
could also influence a Channelwide area-plan, should commercially recoverable oil
and gas resources be discovered-in these areas.

Tanker traffic within the Channel should also be a concern to this group.
Of the 23 leases intersected by the designated Channel shipping lanes, 19 are
operated.by Exxon or Chevron. 14/

GULF/T EXACO/UNION/MOBIL;(GTUM)

Tracts leased by GTUM:4re concentrated in the@eastern end of the Channel (area
1B of Figure 1). GTUM members are the operators in four.area.s.: the Dos Cuadras
field, Union as operator; Pitas Point Uniti.Texaco as operator;@Oak Ridge Unit.,
Gulf as operator; and,the Hueneme Offshore field, Mobil as operator.- GTUM also
owns 70% interest in the Mobil-Rincon.complex, the largest processing plant serving-7-
Channel-leases.- This-facility is presently capable of handting new production from
the Dos Cuadras field when Platform "C" is completed, new production from the
Carpinteria Offshore field if Platform-Henry is installed, and-new production from
the Hueneme Offshore field if Mobil is allowed to.proceed with its Plan of
Development..15/ Furthermore, the facility is capable of expansion with relatively
slight modi-fiZiations to accept production from other potential OCS sources such as
the Pitas. Point or,Santa Clara-Units. 16/ A more thorough review of th-is-facility
is presented later in:this chapter.

From a Channelwide perspective, the GTUM group appears to be.moving effectively

505

toward the goals of area planning and consolidation, but for full realization it
will be necessary to phase future offshore development so as to require minimum
expansion of the Mobil-Rincon facility. Development plans for Platforms C and
Henry, and Hueneme Offshore and Santa Clara Units appear to be compatible with
this strategy. Present uncertainties regarding the Oak Ridge and Pitas Point
units, the proposed Santa Cruz Unit, the Pauley leases, and the Exxon leases make
it difficult to predict levels of production for these areas and to anticipate
when, if.ever, oil and gas from those areas can be delivered to processing facil-
Aties. Nevertheless,.decisions regarding changes in the operation of the Mobil-
Rincon facility and pipeline linkages to the site must not ignore the possibility
of production from these less defined areas.

PHILLIPS

Production from the Phillips portion of the Carpinteria Offshore field reached
a peak in 1969 and has declined ever since. No production expansion is anticipated
from the Phillips lease on the Carpinteria Offshore field; the remaining field life
is estimated at eight to ten years. 17/ Sun's proposal to install Platform Henry
near the Phillips lease may affect tl@e remaining life of the field.

SUN

Current production for Sun is from Platform Hillhouse on the west side of
Tract OCS-P 0240, delivered from the eastern extent of the Dos Cuadras field to
Mobil-Rincon for processing, via Union's Platform A (see Figure 10 for a diagram
of how production is transported in this area). Hillhouse peaked in 1971 and has
declined ever since. In 1970 Sun proposed Platform Henry for the east side of
0240 to tap the western extent of the Carpinteria field, but the application Was
denied on environmental grounds. A similar application was again filed
September 29, 1975, and is currently under review by USGS. Any decision on this
application must consider: (1) the congestion of this are 'a from the number of
nearby platforms and the hazards they pose for the marine terminal operation
directly onshore at Carpinteria; and, (2) the location of processing for the pro-
duced oil and gas.

PAULEY

Future development of the two leases operated by Pauley remains in doubt.
Several wells have been drilled on each, but none has been credited as identifying
a commercial discovery, although the operator describes some of the wells as
11promising." 18/ Activity on these leases, along with the rest of the leases in
the Channel, was suspended after the 1969 blowout. As a direct result of this
suspension, Pauley sued the Department of the Interior claiming that the lease
agreement had in fact been nullified by the Department. 19/ This case is still
in the courts and its likely outcome is not now apparent. Since Pauley et al. have
.no other.OCS leases nor processing capability in the Channel, it is possible that,
if the leases are developed, transportation and processing would be consolidated
with development plans of either the Oak Ridge or Santa Clara Units. Pauley has
undertaken extensive exploration within their tracts along the same geologic trend
which Chevron currently plans to-develop in the Santa Clara Unit. 201

C 0 0 R D I N A T I N G D E V E L 0 P M E N T I N T H E 0 C S 3 5 A R E A

The area leased as a result of OCS Lease Sale #35 presents an entirely

506

different situation from the Santa Barbara Channel: the leases are new; relatively
little geologic data exists to predict the possible occurrence of oil or gas; and,
most tracts are quite remote. Insufficient data on geologic conditions increases
the risks of encountering geologic hazards, and, with such little advance informa-
.tion available, financial risk in exploration and development will also be
considerable. Due to these factors, mandatory unitization.of oil and gas explora-
tion should be considered from the outset in this area.

OUTER BANKS

Three general areas make up the Outer Bank portions of the OCS 35 Area:
Santa Rosa-Cortes North, Santa Barbara Isl-and, and the Tanner Banks (see Figure 1
for the location of these areas). The reader is reminded-that these Outer Banks
are considered among the most significant ecological resources offshore
of southern California. Chapter 16 provides a detailed account of the ecological
importance of these areas.

Distance from s.hore, as it affects transportation costs, will be a significant
factor in determining how, where, and when (if ever) any of the leases in these
areas will be developed. Certainly, transportation costs will be more than those
expected for less remote leases in the Santa Barbara Channel or San Pedro Bay.
The transportation alternatives to be considered will be pipelines and barges or
tankers.

Another factor affecting the potential development of these a reas will be the
selection and design of processing sites and equipment. Several options may be
considered: offshore floating or fixed-structure facilities, island locations,
and sites along the-Ventura County coastline. The number of operators involved,
the timing of development, and the size of reserves discovered will determine the
location and design of the necessary facilities. If the Outer Banks are developed
in a piecemeal manner, the opportunity for consolidated development of these
common facilities could be lost.

Figure 4 shows the location and likely operator for each tract in the Santa
Rosa-Cortes North and Santa Barbara Island areas, while Figure 5 provides the
same information for the Tanner Bank area. For the 29 leases in the Tanner Banks,
seven different operators are expected to emerge for the purposes of exploration:
Arco, Challenger, Exxon, Gulf, Marathon, Shell, and Texaco. Because of the distance
involved in bringing oil and gas to shore,'development and production may be
feasible only with consolidation of transportation options.

In the Santa Rosa-Cortes Ridge North area, 11 leases are distributed among
four different operators in three sub-areas. Any crude oil or natural gas
-discovered in this area could be transported to shore by pipelines in waters never
exceeding 600 feet. If each sub-area is productive, three separate development
plans could result.

.Off Santa Barbara Island only three leases were sold. All three were
acquired by one company (Mobil Oil), thus eliminating any coordination problems in
this area at the present time. An expected problem in this area is whether or not
sufficient resources exist to justify recovery and transportation costs, particu-
larly in view of the threat their development represents to Santa Barbara Island
and its environs. In Chapter 16, Santa Barbara Island is shown to be one of the
most significant natural resources offshore of southern California.

507

!.,st, Pt
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AND SANTA BARBARA ISLAND

Leased Area M Mobil 10 1
A Arco +10
0 0x0co NORTH SCALE
Chevron S Shei i April 1977 C

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OPERATORS:
TANNER BANK Figure 5.
3 Leased Area
A Arco
Ch Challenger
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S Shell VJ L3K 110 KILOMET Tract
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509 Aord 1977 California Governor's office of Piann,n dR
eSearCh
ocs P ECT

SAN PEDRO BAY

Tracts offered, bid on, and leased as a result of Lease Sale #35 are shown
on Figure 6 and as Planning Area 5 on Figure 1. A total of thirteen tracts were
leased in a more-or-less Checkerboard fashion. This pattern may hinder effective
'unitized operations if reservoirs are found to extend into the unleased Spots Of
the checkerboard. Operators for the area include Chevron with four leases,
Shell Oil with four leases, Gulf Oil Corporation with two leases, and Texaco Inc.,
Mobil Corporation, and Challenger Oil and Gas Company with one each. This owner-
ship is shown on Figure 7.

On November 5, 1975,the Acting Secretary of the Interior authorized an amend-
ment to Lease Sale #35 stipulations requiring, in effect, that any commercially
producible resources discovered in tracts 0254, 0261, and 0262 of San Pedro Bay,
extending into other leased tracts, would be unitized. 21/ Conversely, any field
discovered outside of 0254, 0261, and 0262 and proven 'to extend into one of the
three tracts would automatically require unitization as well. This mandatory
unitization was designed to eliminate potential conflicts arising from royalty
differences between the 0254, 0261, and 0262 group at 33.3% and the royalty rate
of 16.6% applied to any other adjoining leases that could result from Lease Sale
#35. The Department of the Interior considered mandatory unitization in the San
Pedro Bay area primarily because it was felt that the three high royalty leases
involved were almost certain to overlie a productive prospect.

Exploration has begun in San Pedro Bay with both Chevron and Shell complet-
ing their first wells on four leases. Shell's first well on OCS-P 301 (Lease
Tract 262) has been credited by USGS as a commercial discovery, and Shell has
completed two additional delineation wells on that prospect. Of the 13 leases,
only Challenger's lacks an exploratory drilling permit at the present time.

It is likely that Chevron or Shell, or both, will be principal operators
in San Pedro Bay. The remaining leaseholders are overshadowed by the dominance
of Chevron and Shell in leaseholding, not to mention their favorable location
with respect to the major structures in the bay. These advantages may lead to
the other leaseholders participating as subordinate participants in any units
formed in the future. Encouraging full unitization of San Pedro Bay tracts,
however, could maintain a controlled level of drilling activity in the bay and
could result in a more systematic assessment of resource potential if exploration
and development schedules are made a part ofthe unit agreements. Full unitiza-
tion for exploration could also contribute to safer operations with regard to the
vessel traffic separation scheme established by the Coast Guard. Like the Exxon/
Chevron/Arco group in the Santa Barbara Channel, Chevron and Shell have the most
to gain by controlled development since they operate six of the seven leases
presently intersected by the vessel traffic lanes. The traffic separation scheme
is shown on Figure 2 of Chapter 20.

C 0 0 R D I N A T I N G 0 F F S H 0 R E D E V E L 0 P M E N T F 0 R
T H E P 0 T E N T I A L L E A S E S A L E # 4 8 A R E A

The area tentatively to be offered for Lease Sale #48 is shown in Figure 4
of Chapter 22. Most tracts to be offered are contiguous with existing lease
areas which have been described above. If Lease Sale #48 is held and leases
are sold in these areas, lease-area plans must consider the effect these new
leases will have on the timing of potential future development and estimated

510

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Santa Monica

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-7
I J i
LEASES AND ROYALTY RATES: Figure 6
SAN PEDRO BAY

Area Offered

16.60/. Royalty Lease
W.3% Royalty Lease 10 1315 110 KILOMETERS :Zo
#1116* 10 13 15 110 MILES kCRES
NMH SCALE15WODO DEPTHCUR\ 11
Bid Rejected A00 197-1 Calt(ofnia Govemor's Office of Plamn nd R,arch
511 OCS
46jECT

alibu Point LOS ANGELES
Santa Monica
S.LT-@JMONI,l BAY In ewo 7 LOS ANGELESCOA
Segundo F (@ANGE CO.

Manh an Beac

Her sa Beach

R -don o Beach
TORRANCE ANAHEIM
NCE
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dfo Seal SANTA ANA
S B c
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T23 C5 Beach

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rfa Beach
L@

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ana Point
[OEM
n Clemente
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OPERATORS: Figure 7
SAN PEDRO BAY

P3 Leased Area
Ch Challenger
C Chevron
G Gulf
M Mobil' 10 1315 110 KILOME 7:
10 13 15 110 MIE
S Shell NORTH SCALE 1 500,000 DEPTH CU
512 Arifil 1977 California Governors Office of Plannin d R search
T Texaco ocs Pk6j'ECT

volume of recoverable petroleum resources for the area studied. Tracts now
tentatively to be offered for Lease Sale #48 but not contiguous to existing
leased areas are found along the San Diego coastline. These tracts can be
divided into three subareas as shown on Figure 1 within Planning Area 6.

A lease-area plan for Planning Area 6 should be undertaken as a part of
the EIS now being prepared for that sale. For the tracts offered in the Outer
Banks areas and San Pedro Bay, planning considerations will be the same as
those discussed above for Lease Sale #35. 'For-the tracts proposed to be of-
.fered in the Santa Barbara Channel and along the San Diego coastline, however,
additional concerns will have to be considered.

The new tracts offered in the Santa Barbara Channel and to the west of'
the Channel included in Planning Area 1 represent the larges t contiguous area
of potential leases. Some of these tracts encounter water depths exceeding
current state-of-the-art technology for development. Additionally, the west-
ward extension of tracts past Point Conception encounter more severe weather
conditions than are experienced in the naturally sheltered Channel. Finally,
many of the new tracts conflict with the vessel traffic lanes passing through
the Channel.

The new San Diego coastline tracts proposed to be offered in Lease Sale #48
represent the first-ever lease sale along this portion of California's coastline
and the first-ever potential for oil and gas development in the San Diego region.
Unlike the Santa Barbara Channel and San Pedro Bay, there has been no onshore or
state tidel'ands development of oil and gas in this area. Lease-area@planninq
for each subarea along this portion of coastline would have to take into account
a wide range of impacts if leases are acquired here and production occurs. Of
major importance to such plans will be visual and aesthetic effects, requirement
for new industrial-type-uses (oil and gas processing plants) in the coastal zone,
pipeline corridor studies, and the possible requirement for marine terminals to
load tankers or barges with crude oil for transshipment to the Los Angeles/Long
Beach Harbors area.

UNITIZATION

Unitization occurs when companies owning leases in a given area or overlying
a subsurface reservoir unify the ownership and control of the area or reservoir
through a unitization agreement. Such agreements provide that a single company
or committee will be the operator for exploration, development, and/or production
of all the leases affected by the agreement. 22/ California's interest in uniti-
zation stems from the expectation that unitizi-tion can lead to the siting of 2Dly
.necessary onshore and offshore facilities and that they may be sited in the least
environmentally sensitive areas.

AUTHORITY FOR*UNITIZATION

The Outer Continental Shelf Lands Act authorizes the Secretary of the Interior,
in the interest of conservation,and the prevention of waste, to provide for uniti-
zation,,poolinq, and drilling agreements. 23/ The courts have broadly interpreted
the conservation of the natural resources @_f the OCS to include "marine life,

513

recreational potential, and aesthetic values, as well as the reserves of gas and
oil." 24/ As delegated under the Act, unitization can be required by the Conser-
vation Manager of the regional USGS Office under OCS Operating Order #11. The
basic premise behind the authority to requ-ire unitization is that, without cooper-
ation, each lease.owner of separate tracts overlying a common subsurface reservoir
would attempt to recover all that can be profitably and legally produced from his
lease, rega'rdless of whether or not his operations serve to optimize economic
recovery from the entire reservoir: "It has been long reCoqnized that the unitized
operation of all or part of an oil or gas poo'l as if under one lease is usually the
most effective and efficient way to produce petroleum." 25/

Unitization has been-identi,fied in numerous environmental planning documents,
including the California Coastal Plan, and in federal environmental impact state-
ments as a practical tool.for controlling offshore development. The Final Environ-
mental Statement for Lease Sale #35 acknowledges that "mandatory unitization could
contribute to more efficient development of discovered resources; contribute to
optimum placement of collection, storage, and transportation facilities; and would
... present only one comprehensive development plan for each producing field. Thus,
reviewing agenc.ies would be able to view the aggregate situation, including potential
cumulative effects of developr,,lent activities, without the need to review numerous,
possibl1v conflicting plans." 26/

BENEFITS OF UNITIZATION

The objectives-of unitization are to conserve resources, to cut the costs of
developing a field or reservoir, and to protect lessees' rights. Unitization can
achieve these objectives because:

1. it allows exploration and development programs to be.based on the nature
of the oil and gas prospects, ratherthan on lease boundaries and ownership
considerations, which are basically irrelevant to the task of locating
and producing commercial deposits of oil and gas;

2. it increases overall recovery from reservoirs by facilitating use-of
the most efficient "natural-drive" and secondary recovery methods, elimi-
nating less efficient competitive practices.that-would otherwise occur; and,

3. it eliminates facilities not vital to exploration or development of leases,
resulting in financial savings to industry from fewer administrative
permits required, plus savings to onshore communities in terms of more
efficient land use.

In a draft policy paper on unitization, Herman Enzer of the Policy Develop-
ment Branch of the Department of the Interior notes:

In order to get some idea of the magnitudes in savings possible
through unitization ' 38 non@unitized fields in the Gulf of Mexico
with diverse leaseholders were examined. It is estimated that of
the 170 production platforms located in the fields, 79- ! or 46%,
would have been unnecessary under unitization..... Considering all
possible savings in costs, it is estimated that a unit plan would.
reduce the cost of a barrel of oil [for this area] by 20 to 40% as
compared to independent production. 27/

Although Enzer later discounts this 20% to 40% range,of savings by ha.1f, because of
the then recent adoption of OCS Order #11 establishing.utilization as a priority

514

objective for OCS development, the conclusion remains basically the same: uniti-
zation will reduce the number of required facilities and can ultimately increase
total production. A recently completed unit agreement reported in industry jour-
nals further illustrates the benefits of unitization by the example of a 50-year-
old, 600-well field in West Texas, the Yates field. This unit agreement, bringing
together 12 oil companies (Marathon, Amoco, Chevron, Cities Service, Continental,
Exxon, Getty, Gulf, Phillips, Shell, Sohio, an.d Union of California) resulted in
doubling the-maximum effi,cient recovery rate to 100,000 B/D. The ultimate recovery
of the field was effectively increased by 200 million barrels (from 1.75 billion
to 1.95-billion barrels). L8/ In evaluating the-effects of unitizati.on, a review
panel found that "anticipated additional-recovery will more than offset the cost
of the program." 29/

By comparison, it is arguable that the Carpinteria Offshore field, straddling
the state/federal offshore boundary near Carpinteria,-illustrates the duplication
that often results from a competitively de'veloped field. Figure,8 shows the Carpir-
teria field and related development.

The Carpinteria offshore field underlies three leases operated by three
separate companies: Chevron, Phillips, and Sun. Chevron and Phillips are currently.
producing their portions of the field, and Sun probably would be also if a platform
proposed by them in 1970 had been approved. Had'Sun obtained permission to install
its platform, a total of five platforms would be located on the field:. Chevron's
portion of the field is developed with platforms Hope-and Heidi; Phillips has devel-
oped its.portion with platforms Houchin and Hogan;,and.Sun proposed to install
Platform Henry on its portion. Chevron has had 66 wells producing at one time, and
59 are now in operation. 30/ Phillips has had 60 wells producing, of which 48 remain
in operation. 31/ Sun's Troposal was-for a 30-well platform. 32/ In addition,
@7 x
Chevron has approval to drill 20 new wells supplementing the 5 now in e istence. 33/
As can be seen from Figure 8, the three companies would have had three separate
pipeline transmission systems delivering their oil and gas to three separate onshore
processing plants. Chevron*transships-crude oil to refineries via its marine
terminal at Carpinteria; Phillips crude is pipelined directly to Los Angeles
refineries or tankered from another marine terminal at Ventura; and, Sun's production.
would have had the same options as Phillips. 34/ Thus, in the absence of uniti"
zation, this field might have been-developed Wil-th.some 169 producing wells (79
for Chevron, 60 for Phillips, and 30 for Sun) from five production platforms
dependent on three sets of pipelines to shore, three processing plants, and two
marine terminals.. Under a unitization agreement, several of these production or
transportation systems would have been eliminated. At a minimum, all production-
could have been transported to a single shoresite processing plant by a single'set
of,pipelines. It is also possible that the field-could have been developed by
fewer production stations located more strategically (for example, four instead
of five), or possibly by fewer surface structures augmented by satellite production
systems on the ocean floor (water.depths over the Carpi,nteria field are-relatively
shallow). Further, unitization would have optimized the number and location of
wells rather than-allowing these matters to be determined by arbitrary lease
boundaries. Finally, the.competitive methods,of producing the field ma well have
y
lowered the ultimate volume of-recoverable oil. 35/

VOLUNTARY V. MANDATORY UNITIZATION

According to Enzer, only 260 1-eases of a total of 1266 in-U.S. OCS waters-
were unitized in March of 1974. 36/ Enzer also notes that less than 4%-of non-
producing OCS leases (i.e., those-in the exploratory phase of OCS development)

34-76658 515

in the U.S. are in units combining diverse ownerships, and less than 20% of
leases currently in production are unitized. 37/ This may be due to the fact
that "the vast majority of producing leases iiFthe Gulf are characterized by
small salt domes and listric pools which are often contained within one lease." 38/
The size of these pools does not preclude the unitization of 'leases for the
.purpose of consolidating transportation of crude oil and natural gas to shore,
yet the sharing of pipelines in the Gulf is the exception rather than the rule.
In other words, despite the-apparent economies and actual increased benefits
from unitization, the vast majority of OCS tracts are not being unitized nor are
offshore pipelines being consolidated. Furthermore, units are generally not
formed until after initial exploration and delineation wells have been completed.
Because voluntary unitization has not resulted in a significant number of units,
especially in the exploratory phase of resource recovery, Enzer's study group
co6cluded that the department should pursue mandatory unitization of frontier
areas. H'e specifically identified the southern California Outer Banks for
mandatory unitization and recommended that additional consideration be given to
the Santa Barbara Channel, which must also be considered a frontier area. As a
part of that study, Exxon submitted a suggested outline for implementing such a
program. The outlined program was designed to expedite the leasing and exploration
of frontier areas. Because it presents a clear and concise case for mandatory
unitization, we haveincluded it in its entirety, with comments by Enzer, as
Appendix A to this chapter.

In response to our draft findings and recommendations, industry representatives,
without exception, opposed mandatory unitization, some equating it with "regulatory
extremism," alleging that it would prolong rather than expedite exploration and
development, and that it would not alter environmental risks. A t@pical response
is that of Chevron: "The amount of drilling and the number of platforms and facil-
ities are not governed by mandatory political maneuvers; they relate to, and
develop from, the geology,-physical geometry of the oil field(s) and the dictates
of inviolable economic factors.".39/

We do not agree with this position. As noted in the preceding section describ-
ing the Carpinteria offshore field, the amount of drilling and the number of-plat-
forms and facilities were clearly not governed by the geology or physical geometry
,of the oil fields but rather by the absence of governmental coordination and indus-
try cooperation. We strongly agree, however, that geology and reservoir geometry
be taken into consideration in forming units and so advocate in our findings and
recommendations.

The position taken by Chevron and others also raises a classic economic debate:
are private sector economic factors really inviolable? 40/ To be certain, industry
repeatedly asserts that (a) their economics are not to Fe violated and (b) that
such governmental intervention, as a policy of mandatory unitization, flies in the
face of the free enterprise system. As discussed in Chapter 18, some economists
believe that the petroleum industry is oligopolistic in nature, rather than a simple
marketplace. phenomenon, and that in fact the very market place in which they do
business is not the unfettered haven where free enterprise exists inviolate. We
assume that economic determinants to development choices are not, in the final
analysis, absolute, especially when certain costs -- environmental, social, or other
are not calculable. Rather, we assume that economic determinants are ultimately
negotiable. Further, we conclude that mandatory unitization in especially sensi-
tive environmental regions such as the Outer Banks, or heavily used areas such as
San Pedro Bay, is essential to minimizing these incalculable costs to other re-
sources the public has declared inviolable.

516

Our findings relative to unitization offshore of southern California indicate
that mandatory unitization in the Santa Barbara Channel is essentially a moot
point as 53 of the 65 existing leases are already unilt-Azed or incorporated in devel-
opment plans or proposals for unitization. Of the remaining 12, ten are controlled
by the Exxon/Arco/Chevron consortium, and two are controlled by Pauley, an indepen-
dent (see "Coordinating Offshore Development in the Santa Barbara Channel" below).
With respect to tracts leased as a result of Lease Sale #35, we conclude that plan-
ning for the coordination of exploration, production, and transportation on an
area-by-area basis (lease-area planning) should precede unitization. This area
planning stage would identify the location and extent of the most promising geologic
structures and the strategies for developing each area. Geologic structures found
to underlie leases of diverse ownership would be scheduled for unitization of
further exploration and development where feasible. Lease-area planning is described
in greater detail earlier in this chapter.

It should be noted here that the privileges of unitization can be abused. Once
a group of leases is unitized, a showing of "diligent and good faith efforts" must
be made to preserve the unit past the initial term of the leases in the unit (five
years). The determination of good faith efforts,is left to the discretion of the
USGS Area Supervisor. Since under unitization all leases in a unit are treated
more or less as if they were one, the drilling of oneor more wells on one lease may
be construed as satisfying this good-faith requirement for all leases in the unit,
thereby extending the term of all the unitized leases. - Hence, unitization may be
used as a lease-holding device, permitting offshore operators to defer the explora-
tion and possible development of certain leases until it is in their interest to
explore them. For example, in the Santa Ynez Unit four leased tracts
have never been explored, there are no current plans to explore them, and there has
been no effort on the part of the Department of the Interior to cause these areas
to be explored.

PROCESS OF UNITIZATION

OCS activities may be unitized at any s-tage of development. The principal
steps required for establishing unitized operations are: (a) the designation of
a Unit Area by the Director, USGS; (b) submission of a unit agreement for approval
by the USGS Oil and Gas Supervisor having jurisdiction over -the area being unitized;
and, (c) submission of plans of operation as may be specified in the approved unit
agreement or as need may arise. A unit plan combines the unit agreement and opera-
ting plan(s).

DESIGNATION OF A UNIT AREA. A unit area may be defined as the submerged lands
recognized as logically subjec:E to consolidated exploration, development, and opera-
tions for the production of oil and gas without regard to separate leaseholdings. 41/
The Conservation Manager of the USGS Regional OCS Office is authorized to require
unitization of offshore leases when a determination has been made that "conservation
will be best served by unitization of a competitive reservoir." 42/ This authority
has not been exercised in southern California, as all existing aTd proposed units
to date have been voluntary. However, mandatory unitization has been provided for
in lease stipulations for three tracts in San Pedro Bay. In this instance, the
operators of these leases must unitize as a condition of approval of a development
plan. The stipulation provides for mandatory unitization only if a discovery is
made and the reservoir is found to underlie two or more leases.

Perhaps unique to southern California has been the designation of unit areas
containing more than one structure. 43/ Typically, a unit area boundary is

517

governed by the geographic extent of a single reservoir or specific geological
volume. 44/ However, in the instances of multiple-structure units, e.g., Santa
Ynez and Santa Clara Units, consideration of administrative and operational
factors may have determined the unit area configurations.

UNIT AGREEMENTS. Unit agreements contain set 'requirements to be met by the
operator for the development of a specified field or reservoir. Unit agreements
also establish the working relationship between the unit operator and the USGS.
A unit agreement may contain the following:

1. a description of the area to be unitized;

2. provision for expansion or contraction of the area;

3. designation of the operator and provision for its successor;

4. requirement for a unit operating agreement detailing a method of reim-
bursement to the operator for costs and expenses and an allocation to
all working-interest owners of the benefits accruing from operations,
and any other agreements they may agree upon;

5. provision that the unit agreemen t prevails in any inconsistency with
6 unit operating agreement;

6. delegation of exclusive rights, privileges, and duties of the parties to
the agreement to the operator, subject to the terms and conditions of an
approved Plan of Operation;

7. requirement that a Plan of Operation be submitted for approval by the
Supervisor providing for exploration or development or both. The plan
shall be as complete and adequate as the'Supervisor'determines necessary
for timely exploration or development or both. The plan must also ensure
environmental protection and conservation of the oil and gas or other
natural resources of the unit area;

8. requirement that prior to production, Participation Area(s) be submitted
for approval by the Supervisor to allocate percentages of unitized sub-
stances to each tract, thereby governing allocation of future production;

9. provision that "all unitized substances ... shall be deemed to be produced
equally on an acreage basis from the several tracts of unitized land within
the participating area .... For the purpose of determining royalty ... each
tract of unitized land shall have allocated to it such percentage of the
production from the participating area as the number of acres of unitized
land in said participating area...";

10. provision for the right of any lessee to relinquish any interests committed
to the unitized area;

11. specific renta.1 and minimum royalty payments and schedules;

12. a specific method by which land not entitled to inclusion in a Participation
Area may be automatically eliminated from the unit agreement;
13. the effective date and term of the agreement (five-year terms are standard)
with provisions for term extension and termination; and,

518

14. right of the unit operator to appear before the Department of.the Interior
for and on behalf of any and all interests affected by the agreement. 45/

The unit agreement does not elucidate the relationship between owners of
interest in the unitized area. That function is reserved for a unit operating
agreement, identified as "any agreement entered into by and between the unit
operator and the working-interest owners for the development and production of
oil and gas from the unitized area with an allocation of costs and benefits on
a basis defined in said agreement." 46/ The USGS requires preparation of such
agreements-but is not authorized to approve or disapprove their conditions.

In 'its standardized form and purpose, the unit agreement is of little help
to state and local planners in anticipating onshore impacts. What may be of
greater use to planners concerned with onshore impacts are Plans of Operations
which may also be required by an approved unit agreement.
PLANS OF OPERATION. There are two basic types of plans of operation (PO):
plan of exploration FMOE), and plan of development (POD). POEs are usually for
one or, at most, a few exploratory well(s). They describe the location, drilling
procedures to be used, and precautions to be undertaken during the operation. A
.POE is generally quite brief -- sometimes only a few'pages. If exploration beyond
..the initial POE is merited, the lease holder may submit supplemental POEs for
.-additional wells. These supplemental plans may be used to confirm or deny dis-
coveries or to delineate the extent of a reservoir.

PODs are prepared by offshore operators who have decided to develop a reser-
voir (discovered through a POE). Usually an initial POD is submitted to the USGS
Oil and Gas Supervisor for his approval, to-be followed by a supplemental, more
detailed POD. The initial POD presents an overvirew of the project, including
summaries of geotechnical review data for the operating area, field history and
reservoir data, drilling plans, platform facilities, offshore pipelines, onshore
facilities, contingency plans, and other relevant material. The initial POD may
be less than 100 pages and would probably contain schematic or prototypical
drawings of the proposed facilities. Following approval of the initial POD,
a s.upplemental POD may be prepared. Supplemental PODs present the same material
mentioned above, but in great detail. For example, the Exxon Supplemental Plan
of Operations, Santa Ynez Unit consisted of seven volumes, each over four inches
thick and when combined weighing 56 pounds. Additional PODs may be submitted as
circumstances demand.

Plans of Operation ar e generally regarded as proprietary because they often
describe oil and gas potential in the area; therefore, they have been generally
unavailable to the public. When such plans are available, they provide the first
real insight to state and local planners of the potenti,al onshore and offshore
effects of specific OCS development. Of particular importance Js the fact that
the plans bind the operator: "the failure of the unit operator to timely drill
any of the wells'provided for in a plan of operation approved under this.Article X
or to timely submit a plan of operation for approval by the su@ervisor or in any
other way to timely comply with the requirements of this (unit agreement, shall,
... result in automatic termination of this agreement ...... 47/

Upon approval of a plan of operation by the USGS, and the nature and scale
of operation anticipated, unitization may require environmental impact assessments
and permits before actual operations can begin. Necessary documents may include
federal EISs, state and local EIRs, local general plan and zoning amendments, and
federal, state, and local building permits.and authority-to-construct certification.

519

The Santa Ynez Unit illustrates perhaps the extreme case wherein nearly six years
elapsed between designating the unit area (September 11,1970) and securing a final
approval (July, 1976) from the Secretary of the Interior, notwithstanding continu-
ing litigation. 48/

It sh,ould be noted that in the case of the Santa Ynez Unit De velopment Plan,
state and local officials were not involved in the project until 1974, after the
massive supplemental POD was completed and a draft EIS prepared. By this time
the development plan was a faitaccompli, in effect disallowing a critical review
of underlying assumptions. Further, discussions of alternatives, such as the on-
shore pipeline or consolidation with other operations, were not comprehensive.
It is possible that the permitting process for Exxon encountered numerous delays
because state and local views were scarcely considered in the early stages of the
plan's formulation.

COORDINATING ONSHORE DEVELOPMENT

The principal strategy considered for coordinating onshore development along
southern California's coastline is "consolidation." This strategy involves
the sharing of existing or new facilities or the concentration of two or
more activities at the same location. Consolidation occurs when two or more com-
panies use the same site or facilities-for development, transportation, processing,
or storage functions, rather than each company constructing and operating a facili-
ty for its own needs only.

A policy supporting consolidation of offshore oil-related facilities is generally
believed preferable because consolidation implicitly represents a reduction in the
number of facilities required to recover offshore petroleum resources, which in
turn represents a proportionate reduction in the number of situations wherein oil
spills or air pollution would be likely to result. Consolidation also requires
less energy and consumes less land. Building fewer facilities also saves money
for the petroleum industry and.thereby may save consumers' money. Various con-
solidation policies are-included at the end of this chapter as Appendix 8.

Of critical concern to this process is the potential and unnecessary dupli-
cation of oil and gas processing facilities. Of equal concern are the alternative
modes of transporting processed crude oil. Processing facilities and transporta-
tion alternatives have been the target of consolidation efforts to date and are
the focus of this discussion because they constitute the major sources of land use
impacts and potential pollution.

Express policies of the California Coastal Act of 1976 and of Santa Barbara
County recommend that facilities related to offshore petroleum exploration and
production be consolidated wherever feasible. The petroleum industry has occa-
sionally agreed to consolidation after a clear public agency.directive to do so.
Ventura County has had some success with this, while Santa Barbara County and
Coastal Commission efforts to require consolidation have thus far been resisted.
In comparison, Scotland has successfully directed industry to consolidate pipeline
facilities, onshore sites, and tanker terminals needed for North Sea operation.
Industry resistance to consolidation is variously based on concern that:

1. some consolidation strategies might increase capital costs., thereby
making small scale, marginal ventures uneconomic;

520

Onshore gas processing plant
(photo courtesy of Exxon).

sd@
N .00,*4@

521

2. the information exchange and inter-company cooperation that must attend
planning for consolidated facilities may lead to loss of competitive ad-
vantage and violation of antitrust laws;

3. the uncertainty of information regarding the petroleum resource on their
own leases already sufficiently complicates facilities planning without
adding the uncertainties of other companies' production prospects and
actual production volumes;

4. flexibility in production and marketing strategies will be impaired by
facilities that must be designed a'nd operated to meet the needs of other
companies as well; and,

5. physical properties of oil and gas produced from different reservoirs
might make the respective substances incompatible and preclude use of
common facilities.

Our findings indicate that, contrary to industry's beliefs, company coopera-
tion required for consolidation will not ordinarily jeopardize technical patents
and proprietary information. Further, necessary inter-company planning efforts
will not ordinarily be subject to antitrust action. We also find that no physical
properties of offshore petroleum resources prevent commingling.

Admittedly, inter-company planning for consolidated facilities is complicated
by the great latitude leaseholders are allowed in proceeding toward development.
And in some instances consolidation of facilities'may raise environmental problems
more serious than those it solves: the increased activities at a single site could,
for example, result in violation of air pollution standards at the consolidated
site, when no such violations would have resulted at smaller, dispersed sites.

Economic analysis of consolidation options by public decisionmakers is also
complicated by:

1. incomplete information about the producible petroleum resource;

2.* incomplete information regarding the investment and marketing strategies
of the individual companies potentially involved; and,

3. inadequate analytical tools for measuring the economic value to society
of environmental improvement, mitigation of adverse environmental effects,
or elimination of the risks of environmental damage.

For practical reasons, this analysis of consolidation is limited to offshore
production stations; pipelines between production stations and processing facili-
ties, processing and related storage facilities; transportation of oil and gas
between processing facilities and customers or refineries; and, staging areas for
crew and supply boat activities. Refineries and related facilities are specifi-
cally excluded because existing California refineries do not depend on California
offshore oil for their location or design.

To establish a clear set of conditions under which consolidation should be
required as a matter of public policy, several examples of currently consolidated
operations and the proposed Exxon/Arco/Aminoil consolidation in Santa Barbara
County were analyzed and are described below. The keY issues raised by these
examples are discussed in question-and-answer form following these descriptions.

522

E X A M P L E S 0 F C 0 N S 0 L I D A T 1 0 N

Consolidation of offshore oil-related facilities to date has occurred largely
as a result of private industry economics. 49/ Where the sharing of a facility
such as a marine terminal is shown to be more economical than.developing a separate
new facility, industry has demonstrated a willingness to pursue this alternative.
Generally, this has occurred where total combined production throughput has been
relatively small. An example of this is the Getty Marine terminal at Gaviota.
Likewise, several offshore-related onshore' oil facilities become concentrated at
one location as a result of advantages such as compatible zoning And surrounding
land uses. Generally, where production from individual operations is relatively
high, industry lacks incentive.to share common facilities. Key examples illus-
trating these principles and the incentives and disincentives that led to them
are described below. See Figures 8, 9, and 10 for the general location of these
sites.

GETTY-GAVIOTA 50/

Approximately 30 miles west of the City-of Santd Barbara and one mile east
of Gaviota, Getty Oil Company owns a 98-acre parcel fronting the ocean and extend-
ing inland approximately 1,000 yards. The site, shown in Figure 10, is presently
used by Getty, Chevron Company USA, Arco, and Douglas Oil. Prior to 1973, Texaco
also used portions of the site (Douglas was not then involved). All activities
are concentrated on an 11-acre portion of the parcel which is bisected by Pacific
Coast Highway (101) and'separated from the ocean and low coa stal bluffs by the
Southern Pacific Railroad.

Present operations at the site include gas processing by Chevron; small scale
oil and gas processing by Arco; crude oil-storage leased by Douglas Oil as a
reserve for future use in their northern Santa Barbara County refinery; and Getty's
truck loading rack, storage, pump ing.- and heating equipment related to its off-
shore marine terminal.

Chevron processes gas from its offshore wells in state leases 2894.1 and
2199.1 directly offshore the Gaviota site and from three onshore wells located
on the bluffs. The processing site is north of the highway, across from the main
storage and marine terminal-operations. Chevron's processed product (natural
gasoline) is pipelined to a storage tank in the main storage area which is in turn
linked to the.submarine pipelines serving the offshore marine terminal. Produced
dry gas is sold into the Southern California Gas Company pipeline which crosses the
@ite, and produced propane is trucked from the site.

Arco has one.well 1.5 miles offshore producing oil and gas from the Alegria
offshore field (state lease 2793.1). The well is connected to Arco's processing
facility at Getty7Gaviota to the north by a 4.5-mile submarine pipeline. Treated
gas is sold to an onsite gas pipeline company; produced oil is stored for trucking
through Getty's truck-loading rack. When Texaco stored crude oil at Getty-Gaviota,
Arco would commingle its treated crude with Texaco's for shipment via Getty's
marine terminal.

Douglas Oil currently leases two 80,000-barrel storage tanks from Getty for
storage of crude oil to be used in the Douglas refinery at Santa Maria. The crude
is produced near Santa Maria and trucked to this storage site for future use or
exchanges with other potential users.

523

Santo Barbara
Figure 8
SUMMERLAND OFFSH SUMInfriand
SUMMERLAND TO PITAS POINT
rpInt*ris

evr I
Chevl`0@, Carpinteria
Oil & Gas Facility
CHEVR@ Chevron, Hazel
PRC. 1824 Chevron,
Marine Rincon Point
CONOCO Terminal Phillips, La Conchita
PRC. 4031.1 Oil Facility

Mobil, Rincon
CABOT Oil Ficilit
ARCO PRC, 429 y
CHEVRON CA I TERIA k-@' MOBIL
DO$ CUADRAS PRC. 3160 Arco, PRC@ 427
Ch n, Sea Cliff -
Hope ARCO R"nCOn CABOT
Union, a Urkion, A PRC. 1466 Island PRC, 410
Heidi rHE; i
(PrUsed) Hogan EXXON 145'
*--AL4 n, a duchin PRC. 3133
Hillhouse
Unioix, C OCS 0166
Pita# Point

OCS 0241. OCS 0240

0. Oil Field
*,- Processing Plant
A Marino Terminal 0 1 2 3 4
PRC. 3184
Platform N Miles
0 Ocean Floor Well Derived from State Lands Commission maps "Tideland Oil
and Gas Development". January 1976, and Division of CPRHCEVRON
0 Artifle'lal Island 3403
Oil af1d Gas Map$ showing oil and gas fields, January 1974.

Shell, Molino
Gas Facility Figure 9

Exxon, Las Flores Canyon
Tajiquas Phillips, Tajiguas
Gas Facility Shell, Capitan TAJIGUAS TO COAL OIL POINT.
Oil Facilities Phillips, Los Llagas
Capitan Gas Facility (Abandoned)

Exxon,
MOL11NO Marine
Phillips Pauley Terminal Aminoil, Ellwood
Naples Oil Facilities
0 Arco, Ellwood
Oil Facility
PHILL, PSPAULEY /1001
PRC.2933 @1- Goleta
TEXACO UNION EL WOOD
PRC.2955 PRC. 2991 Arco, Coal Oil Point
Ln OiI Facility
Ln UNION Aminoil,
PRC. 3503
UNION Marine coal Oil
EXXON Terminal Point
PAC. 3004
AMINCIL
PRC.208 ARCO -Arco Holl Arco
MOBI L 1@@ @ i@
PRC. 3:120 C 01 POINT
SOUTH A
ELLWOOD

CO
AMI, OIL
PRC. 308 JPRC. 309
C) Oil Field
0 1 2 3 4
o Processing Plant
A Marine Terminal N Miles
Platform Derived from State Lands Commission maps "Tideland Oil
and Gas Development", January 1976, and Division of
.- 0
E Tin,

) @Arco
0 1

0 Ocean Floor Well Oil and Gas maps showing oil and gas fields, January 1974.

Chevron, Gaviota
Figure 10 Gas Facility
Getty, Gaviota
Texaco, Gaviota Oil Facility
PT. CONCEPTION TO GAVIOTA Gas Facility
(Suspended) Arco, Gaviota
Texaco, San Augustine Gaviota Oil Facility
Phillips, Conception Oil Facility (Abandoned) GAV OTA tty;
Union Conception Oil Facility (Abandoned) ine
Oil Fac ility 40 WARTA LEGRIA rminal
Poll it CA IENTE MOLINO
Con coolon Union, Shelf
Merine Arco evron, Chwon
Terminal Texaco, Herman Texaco, Helen Shelf
(Suspended) (Suspended) SHELL
---Q -,, CHEVRON
TEXACO PAC. 2199.1
SH E
CEPTION ARCO CHEVRON CHEVRON CHEVRON
U1 PAC. 2793.1 *PRC. 2894.1 PAC. 4002 PAC. 2920.1

ARCO
TEXACO PAC. 2726.1
PAC. 2725.1
UNION H(LLIPS-PAN
PRC. 2979.1 RC.3

0 Oil Field
0 Processing Plant 0
.A Marine Terminal I a
a Platform N Miles
Derived from State Lands Commission maps "Tideland Oil
and Gas Development", January 1976,, and Divis lion of
0 Ocean Floor Well d
Oil and Gas maps'showing oil an, gas fields, January 1974.
n
C__@TA
C4
T a", H@rrnan

O'CEPTION

T A
P I- @11 @PRC, @2726,1
AC CO
2'12@51
UNION
PAC - [email protected]@@@@

The Getty facilities at Gaviota were designed initially as a transshipment
point for its own production from the north-county Zaca Creek field. Crude is
trucked to the site, transferred via the truck-loading rack to one of Getty's
storage tanks,(one 80,000-barrel,tank and one 35,000-barrel storage tank, former-
ly Texaco's). Since the Zaca Creek crude is extremely "heavy," Getty has
integrated into the marine terminal loading system a heating unit to maintain
the crude at a temperature that allows it to flow readily. In the early life
of the Zaca Creek field, Getty considered constructing a pi,peline to the
Gaviota site, but production volumes were never large enough to justify such
a pipeline.

With excess capacity resulting from lower-than-expected production from Zaca
Creek, the marine terminal*operations began to attract the interest of other
companies needing a transshipment point. Texaco, Arco, and Chevron each saw
advantages-in contracting for the marine terminal services and developing
facilities onsite. As Getty's throughput declined and Texaco abandoned its
interests in the site, additional surplus storage became available for Douglas
Oil. Getty was also attracted to this consolidation of offshore petroleum-
related activities: since space was available, tanker scheduling presented no
problem, and more significantly, rental rates were favorable to Getty's local
economics. Fortunately, the relative compactness of operations minimizes the
amount of land area affected by industrial facilities.

EXXON/ARCO/AMINOIL 51/

The first real test of mandated consolidation by a public agency is demonstra-
ted in the proposed consolidation of Exxon, Arco, and Aminoil oil companies in
Santa Barbara County. Exxon proposed a new onshore separation and treatment
facility at Las Flores Canyon, a marine terminal directly offshore, and related
facilities onshore to serve Platform Hondo, now being placed in federal waters.
Exxon's processing plant and marine terminal are designed to handle approximately
80,000 B/D 90MMCF/D. Arco had initially sought approval for the drilling of new
wells from the existing Platform Holly but not for the necessary improvements
onshore to handle the expected increased production of natural gas. A permit for
this initial proposal was denied by the Coastal Commission pending completion of
a more comprehensive application, including consideration of necessary onshore
facilities to accommodate total anticipated increased production of 20,OUO B/D
and 22 MMCF/D. Aminoil has proposed a new marine terminal operation at Dos
Pueblos Canyon, including related onshore pipelines, marine pipelines, and mooring
facilities in state waters, to replace its presently obsolete terminal operations
at Coal Oil Point. Aminoil's proposed operation is designed for "storing and
transporting (via coastal tankers) oil at an anticipated production level of
20,000 B/D".which, for all practical purposes, wholly depends on Arco's antici-
pated production of 20,000 B/D. 52/ See Figure 9 for the location of these
projects.

The plans of these companies are well suited.for a consolidation analysis
since the applications are concurrent. Both Exxon and Aminoil have proposed
new marine terminals.and storage facilities within seven miles of each other;
both Exxon and Arco are proposing onshor e processing plants for oil and gas;
timing of development for the three proposals is compatible; and, the three
proposed development sites are within reasonable distances of each other.

527

The feasibility of various consolidation opportunities among these three
companies is currently under review by Santa Barbara County, which has required
Arco and Aminoil to evaluate their options through the EIR process. Pendi'ng
the outcome of these and other studies, the County Board of Supervi,sors passed
a resolution in 1975 recommendinq that a Permit Arco had applied for from the
State Coastal Commission "be withheld until the issue of consolidation of the
South Coast oil processing facilities is resolved." 53/ At that time, Arco's
Permit application was for the drilling of 17 new weWs from the existinq Plat-
form Holly in state waters. The aDolication did not include a request for the
development of new onshore facilities that would be required in order to accom-
modate the anticipated increased throughout upon completion of the 17 new wells.
On the basis of this and other factors, the Coastal Commission denied the permit
to Arco. In adopting the denial resolution, the Commission noted that:

... piecemeal approach to energy production is not consistent with Coastal
Act requirements for the orderly, balanced use of coastal resources consis-
tent with sound conservation principles.

Given the increased risk of oil snills from the drilling and production of
these 17 new wells, approval of this Dro, ject, independent of clear oro'nosals
for consolidating onshore treatment facilities that will also provide natural
gas, would be contrary to the mandates of the Coastal Act.... a complete RD-
plication -- for offshore petroleum production and necessary onshore facili-
ties, consolidated with others of a similar t.yoe... -- would be consistent
with the Coastal Act and would thus be approved. 54/

Upon appeal to the State Supreme Court, however, the Commission's jurisdic-
tion over this application was ruled invalid because of vested riohts Arco had
accumulated prior to passage of Proposition 20, the Coastal Act of 1972. Arco
has, however, again returned to the Coastal Commission for a permit, this time
for expansion of the existing onshore Processing plant to accommodate the antici-
pated production. See Chapter 21 for a discussion of this current proposal.

Subsequent to the Arco decision, the State Coastal Commission also reviewed
Exxon's application for development of a marine terminal in state waters, pipe-
lines and electrical cables connecting an offshore Platform with an onshore
processing plant, an electrical generating plant to Provide Dower for the offshore
Platform, and miscellaneous appurtenances. A Commission resolution granting a
permit to Exxon Corporation included the following:

The permittee agrees to accent oil and/or natural gas Produced from the
South Ellwood Oil field ... to process, to the extent of its excess capacity
or to the extent of added capacity authorized by any additional Permits or
entitlements of use, said oil and/or natural gas..., and to permit the use
of its proposed offshore marine terminal and/or common carrier (public
utility) pipeline for the shipment of such oil. 55/

The Commission staff noted in the resolution that:

There has been agreement [between representatives of Exxon and the Commis-
sion staff] on many conditions of approval, most notably those involving
consolidation of petroleum processing facilities for other companies of
the proposed Exxon site in Las Flores Canyon. 56/

A major feature of the Coastal Commission Permit to Exxon was temporary an-
proval of the marine terminal (five years) and a requirement that Exxon explore

528

the feasibility of constructing an onshore pipeline, in lieu of a permanent marine
terminal, to transport crude oil from the Las Flores Canyon processing facility to
the Los Angeles area or other alternative destination for refining. The feasibili-
ty of the pipeline would ultimately be determined by an appropriate state agency on
the basis of:

1. a preliminary design study prepared by Exxon;

2. an Environmental Impact Report;

3. the status of government approvals and riqht-of-way acquisitions; and,

4. the determination of the economic feasibility of the pipeline, based on the
projected cost of the pipeline, the amount of oil Exxon olans to trans-
port from the Santa Ynez Unit, the production of other companies anticipated
to be transported through the pipeline, a fair rate of return to the
pipeline owner or operator, a tariff reasonable to the users of the Dipe-
line, the market price of crude oil., and other relevant considerations.

Exxon rejected this approach for determining pipeline feasibility, thereby
rejecting the entire permit. Earlier, Exxon had submitted criteria of its own.
for determining feasibility, effectively setting a dollar limit on Exxon's in-
volvement and a minimum throughput to the pipeline by other nroducers, essentially
placing Exxon in the position of determining ultimate pipeline feasibility. The
Coastal Commission could not accept this method of determination because, in the
opinion of the Attorney General's Office, the Coastal Act of 1972 explicitly pro-
hibited the Commission from making a determination based on such criteria.

In light of the Commission's resolution regarding Exxon and the potential
Arco consolidation, Aminoil's marine terminal proposal is placed in jeopardy.
If Arco and Exxon proceed with consolidation, there would be no need for a new
Aminoil marine terminal. A key question remaining in this situation is the trans-
port mode to be ultimately implemented: the OCS offshore option, the nearshore
marine terminal, or the onshore pipeline. Should approoriate governmental author-
ities determine that consolidation of Arco and Exxon activities is in fact economi-
cally and environmentally undesirable and the companies are allowed to pursue their
separate plans, Aminoil's marine terminal proposal becomes more viable. Then, of
course, the applicability of a consolidation policy to Arco and Aminoil would be
raised.

The possible consolidation of Exxon, Arco, and Aminoil was entertained by
industry reluctantly, at best. Exxon's position is stated as follows: "Under
the free enterprise system, a condition requiring consolidation is basically
unnecessary because there is economic incentive to make unused capacity available
to others." 57/ This qets to the crucial issue of consol.idation: in the absence
.of private i-n-Justry economic incpntive, should public economics be brouqht to bear
on land-use decisions? The unwillingness of Exxon and Arco to enter into a con-
solidation agreement is based on a lack of private industry economic incentive:
each company was pursuing a generally self-sufficient operation. Proceeding on
their own separare d 'evelopment schedules, Arco and Exxon were hardly aware of the
potential sharing or inter-company utilization of common facilities. At the ..
insistence of Santa Barbara County staff, and later the Coastal Commission, these
opportunities were discussed by the two companies, resulting in a general agree-
ment that at least the marine terminal solution can be shared. Analysis by county
staff based on data provided by the two companies, however, indicates that Exxon

529

and Arco crude production is basically compatible and that the Las Flores process-
ing and storage capacity can be adjusted at a reasonable cost to accommodate cur-
rently estimated.crude production peaks and volumes of both companies combined.

The proposed pipeline between Las Flores Canyon and the Los Angeles refinery
area (or alternative destination) is to date the most ambitious Droposal for a
consolidated facility in southern California. The pipeline could potentially
serve as the primary mode of transporting all Channel production to refineries,
eliminating up to 200 Channel-originated trips a year. Considering that-Exxon
ol@.!ns interest in 42 of the 65 Santa Barbara Channel leases (clearly the largest
investor in the Channel), it would seem logical for Exxon to take a lead as
industry's representative in working with government toward Channelwide planning
goals. The Droposed pipeline is Channelwide in significance and, to a degree,
comparable to the Alaskan pipeline, which involves many companies in both construc-
tion and operation.

If Exxon, Arco, or Santa Barbara County had.perceived the Dotential consoli-
dation at the Las Flores site or for a Santa Barbara-to-Los Angeles pipeline
earlier in the permit review process, there might have been less resistance to
the idea of concentrating senaration, treatment, and storaqe activities for the
two companies at the one site. This lack of coordination clearly Doints out the
need for Channelwide planning to provide adequate guidance to sound resource
management in the future.

CHEVRON-CARPINTERIA 58/

Chevron operates an onshore processing plant, a crew and supply boat staqinq
area, and a marine terminal within the City of Carpinteria to service production
from the Summerland Offshore and Carpinteria Offshore fields. The Summerland
field is produced through Chevron-'s platforms Hilda and Hazel; production deliv-
ered to the processing plant from the Carpinteria field is by way of Chevron's
platforms Hope and Heidi. The Summerland field is entirely within state waters
while the Carpinteria field extends into federal waters from the state lease where
the field was originally discovered.

Chevron.maintains two essentially separate and parallel oil handlinq systems,
one for each producing field. The two oil-handlina systems 1)ermit Chevron to
process the two crudes separately and sim 'ultaneously for independent meterina of
throuah.out. The treated and dewatered crudes are then stored on site in Chevron's
217,060-barrel tank (note that commingling does not occur in this tank: the crudes
are fed into the tank at different elevations, and an interface between the crudes
maintains itself without significant blending). When enough processed oil is
accumulated from one field or the other, that portion of the tank is drained off
via pipelines to the offshore marine terminal for transDort.by tanker.

According to the draft EIR for the resumption of drilling from Chevron's
platforms, the majority of recent tanker deliveries have.been to the Chevron
refinery at El Segundo. 59/ The marine terminal is also used for unloading
tankers delivering gasoline and diesel fuel to-a Chevron-owned but snearately
operated bulk plant adjacent to the.processing plant site. Considering the pos-
sibility of an onshore pipeline with the purpose of delivering Santa Barbara
Channel crude oil to refinery market areas, the operation of this marine terminal
could become dependent on offloadinq Droducts only since the loading of crude oil
would no longer be required.

530

In contrast to the parallel oil-processing equipment, gas from-the four
platforms is essentially commingled and treated in one system. At each platform,
natural qas.is separated from the produced liqui0s, "scrubbed," and comDressed at
a low pressure,to go ashore in a pipeline serving each pair of platforms from.the
respective fields. The onshore gas separation and treatment ea 'uipment removes
additional water from the gas and separates natural gasoline, liquid petroleum
products, and dry gas. Some gas is used by Chevron @or energy purposes on-site.
and at the platforms; the remainder is sold. The main reason why only one process-
ing system is required for gas when two are required for oil at this site is that
once natural gas is separated into its component parts, desulfurized, and dehy-
drated, there are no distinguishing characteristics affecting its value.

The significance of the Chevron"Carpinteria operation is that it illustrates
the difficulties pertaining,to commingling produced oil for onshore processinq.
Regardless of whether the crudes are "compatible" or not, the method of valuation
for the purposes of determining the state's royalty, and the value industry re-
ceives from crude characteristics (gravity, sulfur content, others) Iencourage the
development of separate-but-parallel systems, especially when the crudes differ
significantly in economic value. In-Chevron's-case, Carpinteria Offshore oil
(gravity: 250 API) sells for around $5.00/ba'rrel while Summerland@Offshore oil
(gravity: 350 API) is now selling for-around $10.00/barrel. Chevron natural ly
prefers not to commingle the different priced crudes from a market standpoint --
and for taxation reasons as well, since it would complicate.the accounting system
for determining state royalty.

The sharing of crew and supply boat activity by Chevron, Union, Sun, and
Phillips demonstrates industry's knack for getting together even when the mutual
benefit is marainal. The'flexible scheduling of boat use and the-Droximi-ty of the
other.platforms to Chevron's are two factors facilitating this cooperation.

MOBIL-RINCON

"Mobil-Rincon" derives its name from its operator, Mobil, and its location,
the Rincon coastline.. The facility processes production from the Santa Barbara
Channel'federal leases 241 and 240. The site has been identi-fied as having sig-
nificant,capability for accommodating future OCS production by this study and
in the Santa Barbara Channel FES bv the USGS., Lease 241 is operated by Union Oil
Corporation; current production i's from Platforms A and B, with Platform C scheduled
for production by late 1977. Lease 240 is operated by Sun Oil Corporation, Droduc-
ing through Platform Houchin. Leases-241 and 240 overlie the Dos Cuadras-field,
currently the largest.of two OCS producing fields off-,southern California. The
peak rate of production for the Dos Cuadras field was approximately 81,000 B/D
and approximately 40,000 MCF/D in 1971. Current productionJrom the Dos Cuadras
field is approximately 30,000 B/D and 13,000 MCF/D.

Mobil-Rincon covers approximately 140 acres on a terrace along the coastal
bluffs of Ventura County, approximately 3.4 miles southeast of the Ventura-Santa
Barbara county line at Rincon Point, and 1.2 miles due south of Ri,ncon Mountain.
The site covers level to gently roll.ing topography bounded by increasingly
steeper land to the north and east, and exceedingly steep b,luffs to.the south
and west. Of the 140 acres, 20 on the north are reserved as a buffer zone, as
a result of permit conditions-issued by Ventura County, leaving 120 acres
developable. Approximately-32 acres are currently developed for the processing.
plant and a 268,OOU-barrel storage tank owned by the Ventura-Pipeline-

531

Company (see below for a description of this operation). An estimated five of
the 32 acres are available for expansion without grade preparation. An additional
ten acres adjacent to the processing plant are graded to a uniform gradual slope
and could be utilized with minimal grade modifications. The rematning 78 acres
are in a relati-vely natural state of rolling grass and brush-covered terrain. The
operations of.the bluff-top site depend on a pump station and offshore-to-onshore
transfer equipment at the base of the bluffs.

The @10il-Rincon facility, includina the land, ea.uiDment, access road, DUMP
station, and offshore-to-onshore equipment, is presently owned by Gulf, Mobil
Union, and Texaco (the GTUM group) and Sun, Marathon, and Superior (the Sun g;oUp).
The GTUM group purchased the site in 1968 in anticipation of OCS production they
expected as a result of the leases acquired in the February 1968 Channel lease
sale. The Sun group bought in to the operation in 1969 and collectively hold
30% interest in the facility. The Mobil-Rincon facility is operated by the Mobil
Corporati on.

The Ventura Pipeline Company owns a pipeline 'connecti-no the Phillips-La
Conchita processing plant on the north to the 268,000-barrei storage tank at
Mobil-Rincon and a.pipeline continuing south to several transfer points near the
City of Ventura. The Ventura Pioeline Companyalso owns the storage tank at
Mobil-Rincon. The pipeline company consists of the GTUM group, the Sun group,
the owners of Phillips-La Conchita (Phillips Petroleum, Cities Service Oil Company,
Continental Oil Company), Arco, and Chanslor Western. The company is operated by
the Mobil West Coast Pipeline Company, a subsidiary of Mobil Corporation.

The significance of the Mobil-Rincon facility lies in its advance Planning
and the degree of industry cooperation. ReCoqnizing at the very outset of the
Santa Barbara Channel development that the GTUM group could be responsible for as
many as four offshore units ihat could begin production at various times, the
oper.ators designed a facility with considerable expAnsion potential at a site that
was compatible with local land use policies. The system design anticipated crudes
of differing characteristics and therefore allowed for comminglinn managed through
a complex accounting system. This accounting system has facilitated the coopera-
tive joint-venturing of GTUM with Sun Oil, an entirely separate producer, and will
facilitate the entry into the system of several additional units, such as Pitas
Point, Hueneme Offshore, Oak Ridge, and Santa.Clara. Furthpr consolidation is
achieved by the GTUM group in its Ventura Pipeline Company agreement, which has
been expanded to include three other operating groups.

I S S U E S R A I S E D B Y C 0 N S 0,L I D A T 1 0 N

A number of significant issues concerning the validity of consolidation were
mentioned earlier. The following paragraphs illustrate in greater detail some of
the consequences that might result from adopting consolidation as a public policy.

1. Will technical patents and proprietary information necessarily be
jeopardized by the.sharing of production-facilities?
No. Generally, new facilities us'e the most modern technology available, and
new innovations are quickly assimilated industry-wide. Technological innovations
protected by patents were never identified by industry representatives as a con-
straint to consolidation of existing or Drooosed facilities. The cutting edge of
technological innovation in the petroleum Industry is in the exploration and
refining phases of resource exploitation, not in the development and production

532

phases. Even if high technology were present in shared facilities, the
"sharing" rarely if ever poses a security problem. The common practice used
in sharing facilities is for the partners to contract for services, with one
partner acting as operator. The non-operating partners then limit their
concern to volumes of throughput and leave the means of handling the oil.and
gas up to the operator. Proprietary information such as exploration results,
long-range planning strategies of individual companies, or oil and gas volumes
moving into various markets is rarely if ever developed at production
facilities, although the raw data for such information may come from such
facilities, and hence would not be exposed to competitors.

2. Will industry violate antitrust laws through the cooperation imolicit
in a2ency-initiated.or approved consolidation Proposals?

Not by this type of working agreement alone. Numerous cooperative agreements
existing in offshore-related petroleum development in southern California have
operated for years with federal, state, and local approval and have never been
challenged in court. Antitrust concerns become meaningful when the actions of
companies have the effect of defrauding the public or competitors through control
of the market -- not when they collaborate for the purposes of increased effici-
encies or public benefit. Like most states, California statutes-provide in effect
that cooperative agreements implicit in consolidation or unitization proposals,.
when approved by a regulatory agency of the state, shall not be construed to violate
the state antitrust laws.

3. What costs or benefits result from commingling crude oil? When is crude
oil "incompatiBle?"

No Physical properties of offshore petroleum resources literally Prevent
commingling. The commingling of crudes can occur at a gathering point of pipe-
lines from several production stations; at the inlet tank to a orocessing fac.ilit.v;
at treatment stage; at the storage tank awaiting shipment to a refinery; or in
the tanker or pipeline carryinq ihe crude to the refinery. Comminglinq of Pro-
duction.is specifically provided for in the federal regulations governing OCS
operations: "...the [Area Oil and Ga;l supervisor may authorize the lessee to
move production from the lease to a central point for purDoses of treating, measur-
ing, and storing, and in moving such production, the lessee may commingle the Pro-
duction from different wells, leases, pools, and fields, and with oroduction of
other operators." 61/ Oil companies tend to consider crude oil to be "incompatible"
when accounting pr-oblems occur.

Accounting problems involve keepinq track of the percentage owned by each
company of the commingled production; the financial investment by each involved
company in the exploration and development of the producing field(s); the proper
allocation of actual production costs; and the allocation of royalty payments
accruinq from each lease involved. It also involves Projecting market allocation
strategies for the antici'patell Production. From a-strictly administrative point
of view, crude oils become incompatible when the costs of setting up an adequate
accounting system Pxceed the calculated benefits of commingling. The "costs" may
be purely administrative or they may reflect inter-company competition. The
costs of setting up an adequate accounting s 'vstem are not a substantial or siqni-
ficant economic Constraint to commingling when compared to the investment typically
required to produce offshore oil or the ultimate value of the oil produced. None-.
theless, industry sometimes views the economic incentives to commingling as inade-
quate to overbalance the accountinq-problems. An example is the Chevron-Carpinteria

533

case, which contrasts with the Mobil-Rincon case, where the incentives were
effective.

The combination of unlike crudes always results in the averaginq of respec-
tive characteristics in proportion to the volumes mixed: gravity, sulfur content,
and viscosity are the critical factors. If the crudes are identical, there will
be no loss or gain involved. If the crudes differ significantly, the combined
product will represent an average value. The main consequence of commingling
crude oils, from the producer's standpoint, is the difference in price a refiner
will pay for it, the price varies according to the demand for types of crude.
Also affecting the producer's decision to commingle is the effect it will have
on the royalty paid to the State Lands Commission or USGS, depending on whether
it is in state or federal waters. Both the State Lands Commission and USGS apply
their royalty charges to the lease from which the production originates and base
their royalty on the value or amount of crude produced from a given lease after
water and gas have been separated. The value of the crude is determined by the
oil's gravity, sulfur content, and viscosity, factors that vary over the life of
a producing field. Water content must be less than 3% by volume (generally, to
reduce the water content to this percentage requires an elaborate processing
facility not easily accommodated at an offshore Production platform). If pro-
duction remained constant from various leases and the crudes were identical, it
would not be difficult to determine how much oil is being Produced from which
lease, as well as the quality of the re@pective oils if they are commingled
before reaching a metering station. The problem would be worsened if a Droducinq
field spanned state and federal waters because the methods of computing royalty
rates differ.

4. If facilities are to be shared or consolidated, how can equitable use,
liability, and access be guaranteed? What phasing problems would occur?

When two companies approach the idea of sharing a new facility to produce,
transport, or process petroleum resources of identical volumes, characteristics,
and production schedules, there are few or no problems in making the necessary
arrangements. But these circumstances have.been virtually non-existent in the
recent past. More commonly, two or more companies are not ready to enter produc-
tion simultaneously, their ultimate volumes and rates of production vary signifi-
cantly, their facility requirements may vary, and their risks of environmental
damage differ appreciably. One product may be extracted at a high pressure, or
it may be more volatile, more aromatic, more viscous, or higher in sulfur content
than the other. Each of these factors could warrant specialized attention not
required by the other product. Potential equity problems occur when the Parti-
cipants in a proposed shared facility begin to allocate the expenses of developing
a system that must serve the specialized needs of two or more production plans.
Since volume and rate of production vary dramatically over time, the deqree,of use
of certain facilities would likewise vary, resulting in differences of opinion as
to the responsibility for facility operation and any associated liability.

Another potential equity problem exists when new production begins and the
producer is obligated by a governmental agency to unitize or consolidate with an
existing operation in the interests of conservation. Proverbially, the existing
operator has the new producer over a barrel: it can charge the Producer for access
to the established system ostensibly to defray the costs of developing the originaT
facility, even if,it is already paid for.

534

In order to reach an equitable way to share facilities, public agencies such
as USGS should more clearly mandate Procedures for establishina reasonable Joint-
venture conditions. For such mandates to be entirely effective, greater coordina-
tion -- perhaps joint advisory boards -- should exist between state and federal
agencies to better integrate.the necessary onshore components to offshore produc-
tion operations. Together, state and federal agencies could introduce guidelines
for joint ventures that would identify formulas for cooperative agreements consid-
erinq the various equity, liability, and access questions that could be raised.
Phasing in and out of production poses another distinct problem for facility
Planners. Not until.fairly late in the development design staqes can industry
Predict with any reasonable degree of certainty the rate of production over time,
including the variable water-to-oil ratio which often becomes a critical factor in
facility design. Although companies begin toqether (i.e., are awarded leases at
the same time), they explore, develop and produce on extremely variant
schedules, and the possibility of subsequent lease sales in the same area almost
certainly guarantees-different start-uD.times. With companies operatinq under
such diverse schedules, and with the vast uncertainties as to how much
oil and gas might actually be found and where, the design of facilities to
accommodate more than one user generally transcends the planning capabilities of
individual companies.

A potential solution to these problems lies again with public agencies.
USGS, the State Lands Commission, the Division of Oil and Gas, or the Coastal
Commissions should take the initiative Jointl 'v, forminq a clearinghouse for off-
shore petroleum production planning. For understandable oroprietary and competi-
tive reasons, industry-has not demonstrated an interest in tackling the comnlexi-
ties of equity or phasing problems, especially to facilitate consolidation. Yet,
if consolidation reduces initial costs to industry, esoecially to the smaller
independents, as well as serving public goals of minimizing the effects of offshore
oil, then it would seem to be in the public interest that governmental aqencies
provide this clearinghouse.

5. If consolidation were required, what economic hardships would be suffered
by industry? What economic gains would be enjoyed by industry?

Whether consolidation consists of the concentration of several facilities or
activities at the same site, or the sharing of one facility by two or more companies,
industry need not suffer economically. A1.1 apparent inequities can be elimina@ed
*in a carefully considered consolidation by means of compensation and comprom-ise.
For example, some market flexibility could be lost and certain scheduling Preroqa-
tives of individual Companies could be hindered, but at the same time operational
efficiencies would accrue from a consolidated facility. Fewer employees would be
required and capital investment could be reduced since fewer facilities would be
built; and fewer administrative delays affectinq oil development would take place.

6. At what staqe in the resource development process should consolidation be
considered?

Preliminary production planning by industry begins with identifyinq the best
means of recovering the resource, i.e., platforms and ocean floor wells. Following
preliminary planning, an operator prepares a develonment olan which will describe
the production system, schedule the phasing of development and production, and
identify alternatives.for transporting and processing produced resources. This
stage, which takes place often from one to three years before production begins,

.535

is the logical point to consider the potential for consolidating anticipated
production with other proposals or existing facilities. If state aqencies are
to take a greater role in coordinating offshore development, they should be
made aware of development planning by industr@y: review of development plans
will be crucial to this task. In the Dreparation of such plans, it would also
be wise for industry to consult with state and focal agencies to identify d poten-
tial sites for onshore activities compatible with local and regional lan use
planning goals.

7. If consolidation results in fewer facilities, what effect will this have
on local job markets? Local services? Local tax base? Local land use planning?

Offshore.oil production is basically a capital-intensive industry and not a
high employer of local labor. Dependinq on what is consolidated, Dotential new
jobs will be reduced. Current offshore petroleum-related jobs are fairly secure
at this time and likely future oroduction from the Santa Barbara Channel and the
southern California borderlands area can only result in more jobs, though perhaps
fewer than if consolidation were not anticipated. AlthoUqh taxes generated by '
offshore-related development are nuite helpful to local communities, the relative
effect of petroleum-related jobs is virtually negligible in all large cities.

@Some public service agencies operate more efficiently when consolidated
facilities exist. Consolidation re'duces the number of facilities requiring
periodic visits or surveillance by units of the fire and police departments, the
petroleum administrator's office, the local Air Pollution Control Districts, and
many others. Offshore oil-related labor, even cumulatively, will be relatively
insignificant and hence would probably not contribute inordinate demands on addi-
tional services such as hospitals, schools, garbage collection, etc.

Local, taxes will be affected to the dearee that consolidation represents
the construction of one fai 'rly large facility ins tead of two or more smaller-
sized facilities. These theoretical tax losses to the local economy, however,
must be related to the reduction in infrastructural costs resulting from the
favorable land use planning facilitated by a consolidation policy. By concen-
trating or minimizing the number of new or existing facilities for offshore oil
and gas production, the land that might have been converted to offshore-related
facilities would remain available for some other coastal-related development.
The effect of consolidation on land use planning is Dotentially beneficial provided
local government, with the aid of state agencies as necessary, adequately'plans
and zones for consolidated offshore-related facilities.

8. If consolidation of processing plants results in fewer but larger
facilities, what effect will this have on ship or truck traffic?

Processing plants with larger throughput capacities will require more fre-
quent transfers of produced oil, gas, gas by-products (butane, propane, natural
gasoline), and sulfur compounds. It is possible that the number of tanker move-
ments could be reduced by the use of larger tankers if offshore marine terminals
related to the expanded processing plants can handle the deeDer draft ships. Tank
trucks, however, appear to have reached maximum size and hence their use is direct-
ly dependent on the volume of substances to be moved.

Tanker or tank truck congestion is a critical problem that must be addressed
in any facility consolidation plan because of potential environmental risks.
Since truck movement of produced by-products seems unavoidable, the selection of

536

future sites for increased 'processing activity should thoroughly consider highway
access problem's and conflicts. An increasingly serious Prob-lem is the use of
tankers servicing consolidated processing plan1s. Serious consideration should
be given to pipeline alternatives for either transportinq treated crude to marine
terminals in less hazardous circumstances or directly to the refineries-. Site-
specific studies will be needed to evaluate the Dotential risks-of truck or
tanker movement, as no simple rule exists for determining excessive congestion.

9. if consolidation of orocessinq plants results in fewer but laraer
facilities, what effect will this have on oil soill risks?

Oil spill risk is more or less a function of the frequency with which oil is
transferred (from latform to pipeline to processing plant to storage tank to
tanker or pipeline@ although most major oil spills are known to be the result of
human error. If consolidation results in increased throughput and larger but
fewer tankers,.Dotential oil spill risk is reduced, although spill size may be
larger.

10. If consolidation of processing plants results in fewer but 1 arger
facilit-i-es, what effect wi-11 this have on cumulative air nuality?

Given the present state-of-the-art, it is virtually-impossible to eliminate
hydrocarbon vapor emissions from loading crude oil into tank ships or at'various,
junctions within a processing plant. Numerous records of fugitive emissions
aboard tankers, at marine terminals, and at processing plants have been made.
The net result has been to demonstrate that air quality is a critical concern for
offshore petroleum planning.

A crucia*l issue facing a consolidation policy is the effect a consolidated
(concentrated) solution would have on-air quality versus@the dispersion of facili-
ties.which now exist. Consolidation could result in creating a "hot spot" of air
-pollutants with potential-ly severe local effects.whereas dispersion of facilities
would result in distributing pollutants over a wider-area. Two facilities, however.
will have..twice.as many outlets for fugitive emissions as one, resulting in the
po-ssibility of a net increase in regional air pollution. Aqain, no handy guide-
lines exist for choosing between consolidation or dispersion.

11. If consolidation results in fewer but larger facilities, what chanaes in,
potential fire hazard can be exnected?

Fire hazard is a function of the amount of volatile material on hand. Fire
risk is determined by,the number of times the material is transferred from one
vessel to another. The hazards of fire at a consolidated facility may be greater
than at a smaller facility, but the risk will be smaller because it is easier to
monitor one facility than two or more.

12. If consolidation results in fewer but larger facilities, what changes in
ootential visual impacts can be expected?

Visual impacts are a function of the degree-of visibility.of a.facility and
the amount of contrast it reDresents with respect to its surrounding environment.
Visual impacts are. primarily a siti,nq Droblem.- Generally.sDeaking, where scenic
values are highly regarded, -consolidation of onshore-facilities at sites that are
well screened from public viewing points may significantly reduce much of the.
public opposition to onshore industry activiti-es.

537

C 0 N C L U S 1 0 N S A N D R E C 0 M .M E N D A T 1 0 N S

"Oil and gas development shall be permitted ... if ... new or expanded
facilities related to such development are consolidated to the maximum extent
feasible and legally permissible, unless consolidation will have adverse environ-
mental consequences ..." (the California Coastal Act of 1976).

An obvious pitfall of consolidation policy will be in determining the degree
of consolidation considered "feasible" and "economically feasible." The Coastal
Act of 1976 reduces the definition of feasible to "capable of being accomplished
in a successful manner within a reasonable period of time, taking into account
economic, environmental, social, and tec'hnoiogical factors." 62/ A policy advo-
cating consolidation must also recognize relationships to environmental and
economic goals of local and regional governments as they would affect offshore-
related development, as well as industry prerogatives regarding facility siting.
But the most difficult obstacle facing the application o 'f a consolidation policy
is the consideration of fluctuations in production and variations in start-up,
peak, and'tail-off stages of an offshore field's productive life. These are
variables not easily accounted for in a broad policy statement. In the final
analysis, the policy statements must be backed up by resnonsible decisionmaking
that can piece together the sometimes divergent, competitive, and temporal
variables affecting the siting and design of petroleum facilities.

COSTS AND BENEFITS OF CONSOLIDATION

The costs and benefits of consolidation are not readily-quantifiable: there
are as many permutations of potential consolidated operations as there are offshore
lease holders, commercially producible fields, and onshore processing facilities.
Of the examples described, consolidation of offshore-related activities occurred
both voluntarily and in compliance with government stipulations; in no instance
was it indicated that consolidation adversely affected the economic viability of
the overall resource recovery process. In fact, the sharing of facilities, such
as at Gaviota, contributed materially-to the operation's solvency. However, the
ultimate desirability of consolidation, as well as its-feasibility, will have to
be determined on a case-by-case basis, since factors such as air pollution may
conflict with other,basic environmental goals. A summation of some of the benefits
and costs is outlined below.

BENEFITS OF CONSOLIDATION

1. Consolidated onshore processing plants may initially require longer
underwater and land pipelines between processing sites and offshore production
stations.

2. Air pollution hot spots may occur.

3. Unless commingling, royalty and "compatibility" problems can be worked
out, a consolidation requirement may simply result in two parallel systems side
by side.

4. Accounting problems of a consolidation proposal may lead to legal and
financial problems between petroleum companies or between a governmental unit
and a petroleum company. This could produce delaYs in the resource development
process.

538

5. Assignment of liability for oil sPills, air pollution, etc., is
complicated.

RECOMMENDATIONS

1. Institutional arrangements should,be designed to insure the coordinated
and pla'hned development of offshore resources with the least environmental damage
possible, both offshore and onshore. Possible institutional organization could
include a l.ocal government advisory board made up of representatives from southern
California governments, with authority to advise a responsible state or state/federal
agency in negotiating with and overseeing petroleum industry activities. The ex-
press objective would be to minimize onshore impacts through the coordinated and
planned development of new, possibl 'Y consolidated fa.cil.ities and the expansion or
abandonment of existing facilities.

2. Detailed studies should be done to determine practical applications of
a consolidation policy in thefollowing situations:

a. to clarify the remaining options open to the Exxon/Arco/Aminoil
proposed consolidation;

b. to identify and recommend appropriate options for onshore delivery
and transportation modes for production from the Santa Clara Unit,
Hueneme Offshore field, Pitas Point Unit, Oak Ridge Unit, and San
Miguel Unit;

c. to develop a Channelwide production scenario with emphasis on the
ide'ntification of potential landfalls for all production and the
alternative transportation modes for subsequent shipment to market;
d.- to develop a schematic production and transportation scenario for
the existing lease areas from OCS Lease Sale #35; and,
e. to identify and recommend appropriate options for onshore delivery
and transportation modes for the San Pedro Bay unit(s).

539

FOOTNOTES

1. See Appendix 3 at end of this report for a complete inventory of petroleum-
related [email protected] the coastal zone.

2. See generally, pages 1-163 to 1-177 of Volume 1 of United States Depart-
ment of the'Interior, Geoloaical Survey, Final Environmental Statement -- Oil and
Gas Development in the Santa Barbara Channel Outer Continental Shelf Off California,
1976. This section does not include marine terminals.

3. See footnote 1.

4. United States Department of the Interior, Bureau of Land Management,
Final Environmental Statement -- Pronosed 1975 Outer Continental Shelf Oil and
Gas General Lease Sale Offshore Southern California (OCS Sale #35), 1975, 0. 1-183.

5. Ib.id., P. 1-183.

6. "Lease now, plan later" is a common theme through much of the comments
received on.the OCS Sale #35 EIS (see Volume 5). This theme was a part of a suit
brought by the State Attorney General (Complaint, California v. Kleppe, Civ. No.
75-1943 [D.C., filed November 1975]). This theme was also apparent in the suit
which overturned Lease Sale #40 on the.east coast (NRDC v. Secretary of the Interior,
No. 76C 1229 [E.D.N.Y., February 171 1977]).

7. The OCS Lands Act confers broad discretionary powers on the Secretary
of the Interior in carrying out the qeneral mandate of the Act. To "manage.the
OCS for the Drevention of waste and the consqrvation of natural resources," the
Secretary has authorized,the conducting of vii)eline corridor studies by BLM for
offshore leased areas. Notably, none @ave been undertaken offshore of southern
California.

8. Outer Continental Shelf Lands Act of Aunust 7, 1953, 67 Stat. 462;
43 U.S.C. 133(a)(1), Section 5(a)(1).

9. California-Coastal Act of 1976, PRC, Section 30262.

10. 30 C,F.R. 250.1 and 250.11.

11. See for-example, Volume 2, Dp. 384-400 of 'Final Environmental Statement
Pror)osed 1975"Outer Continental Shelf Oil and Gas General Lease Sale Offshore
Southern CaTi@forni@a-OCS Sale'#@5), 197@, by the Bureau of Land Management, Depart-
ment of Labor.

12. If Exxon's four leases in the middle of.-the Channel were com-
bined with the Oak Ridge Unit, the number of total operating areas would-be-
reduced to 12, and the Exxon/.Chevron/Arco group would be the operator of six.

13. In a letter dated July 21, 1976, from Ronald Coleman, Assistant Secretary,
Proqram and Development,.Department of the Interior, to Melvin Lane, Chairman,
California Coastal Zone Conservation Commission, informing the Commission of the
Secretary's decision to allow Exxon to proceed with-their "offshore alternative,"
Mr. Coleman states:

... We are greatly concerned over the cumulative impact of OCS development on
the coastal resources of California. We believe that we,share an objective

5AO

with the State of California of getting the Santa Barbara Channel Oil into
use by our citizens at the least possible cost, where such cost is reckoned
as both environmental cost and cost of economic,resources. In this sDirit,
let me urge the State to undertake a Channel-wide study of the likely
scenarios for development of both the state and federal leases and an evalu-
ation of alternative arrangements for handling the oil oroduced.

Although we concur with the need for such a study, we respectfully disagree
with the strategy for preparing it. The Department of the Interior should take
a major role in preparing the study, including the funding of it, because they
are the landlord of the offshore area to be planned for.

14. See Plate 1: Map Showing Oil and Gas Fields...Final Environmental
Statement -- Oil and Gas DeveloDment in the Santa Barbara Channel Outer Contin-
ental Shelf Off California, 1976, Geolocical Survey, Der)artment of the Interior.

15. Personal communication to Allan Lind, from R. M. Voils, Western
Producing Area Projects Manager, Mobil Oil Corporation, July 28, 1976.

16. Ibid.

11. Personal communication to Allan Lind, from B. U. Peister, Area
Supervisor, Phillips Petroleum, July 28, 1976.

18. Letter, dated April 12, 1977, from James B. Anderson, Vice President,
Exploration, Pauley Petroleum, Inc., to Allan Lind, OCS Project.

19. U.S. Court of Claims Docket #197-69.

20. Anderson letter, April 12, 1977, oD. cit.

21'. United States Department of the Interior, Bureau of Land Management,
Outer Continental Shelf Off Southern California Oil and Gas Lease Sale #35
Amendment of Sale Notice, November 5, 1975.

22. 30 C.F.R.,Part 226, "Unit or Cooperative Agreements."

23. Outer Continental Shelf Lands Act of Auqust 7, 1953, 67 St.at. 462),
Section 5 (a)(1).

24. Union v. Morton (1975) 512 F 2d 743, 749, citing Gulf v. Morton (1973)
493 F 2d 141.

25. H. Enzer, "Unitization of Offshore Oil and Gas Operations, Draft,"
Department of the Interior, Mineral Policy Development Branch, 1974, o. 1.

26. United States Department of the Interior, Bureau of Land Management,
Final Environemntal Statement -- OCS Sale #35', 1975, Vol'. 2, D. 756.

27. Enzer, op. cit., pp. 49-50.

28. The Oil Daily, July 1, 1976.

29. The Oil and Gas Journal, May 31, 1976, p. 41.,

541

30. Letter dated June 22, 1976, form Hillary A. Oden, Acting Conservation
Manager, Western Region, Geological Survey, United States Department of the
Interior to the Office of Planning and Research.

31. Ibid.

32. United States Deoartment of the Interior, Geological Survey, Final
Environmental Statement -- Santa Barbara Channel, 1976, Volume 2, D. 111-43.
T-he most recent design for Platform Henry, submitted in 1975, calls for only
21 wells instead of the original 30.

33. Final approval for this project was obtained by Chevron from the State
Lands Commission, September 30, 1976, Sacramento, California. No permit is
required from the Coastal Commission.

34. See Chapter 21 for a detailed description of Sun's proposal and its
options. In brief, when Sun installed Platform Houchin, they aDDlied for permits
to construct a new processing plant on vacant land adjacent to Ohillips-La Conchita.
This proposal was rejected by Ventura County, resulting in Sun acquiring interest
in, and arranging for processing by, the Mobil-Rincon processing plant. Sun's
proposal for Henry is to pass produced crude oil and natural gas to Platform Hill-
house for Processing and then deliver it to Mobil-Rincon via existing pipelines
for sale and transshipment to refineries.

35. During the time that Sun Oil has been in court, from 1969 to the present,
some drainage of the Sun portion of the Carpinteria field may have occurred as a
result of the continued operation of the Phillips Platforms. Sun representatives
have indicated to the Office of Planning and Research that if the drainage is
significant, it may no longer be economic for them to develop thetr portion of
the reservoir. Sun is currently evaluating an exploratory well to determine the
extent of drainage if any. If Sun does not develop its portion of the re,servoir,
because of the alleged drainage, whatever crude oil that Might have been recoverable
may be lost. It is not reasonable to expect continued drainage by Phillips
platforms to recover the more distant deposits of Petroleum in the field.

36. Enzer, on. cit., pp. 29-30.

37. Ibid., p. 30.

38. Letter dated October 7, 1976, from Tom Hudson and others, Chevron USA,
Inc., to the Office of Planninq and Research.

39. Letter d@ted March 11, 1977, from T. A. Hudson and others, Chevron USA,
Inc., to the Office of Planning and Research, p. 11.

40. Inviolable: "not to be violated, not to Ne profaned or injured; sacred,
indestructible...," Webster's New World Dictionary, William Collins & World
@u'b'lishing company, Mew York, 1974.

41. Adapted from Unit Agreement for the Development and Operation of the
Santa Clara Unit Area, Channel Islands Area, Outer Continental Shelf, Offshore
California, Standard Oil Company of California, 1973, p. 2.

42. United States Department of the Interior, Geological Survey, Conservation
Division, Pacific Area, OCS Order No. 11, Effective May 1975, Oil and Gas

542

Production Rates, Prevention of Waste, and Protpction of Correlative Riqhts,
Paragraph 16, C.

43. Both the Santa Ynez Unit and the Santa Clara Units encompass two or more
structures. The Santa Ynez Unit contains the Hondo field, now being developed,
as well as the Pescado'and Sacate' fields. There has been speculation that a
fourth field exists within the Unit further,to the west. This field first appeared
on a map published in 1969 by the Geological Survey titled-, "Man S-howinq Oil and
Gas Fields, Leased Areas, and Seeps in the Santa Barbara Channel Region" (Interior
Geological Survey, Washington, D.C. -- 1969 -- G70137). On subseouent maps of the
same title published by the Geological Survey in 1973, 1974, and 1975, this unnamed
field no longer appeared. On a map published by Exxon Company, USA, in 1975, how-
ever, this phantom field has reappeared.

44. Personal communication to Allan Lind, from Maury Adams, Staff Petroleum
Engineer in charge of offshore operations, Pacific Area, United States Geological
Survey, August 19, 1976.

45. Standard Oil Company of California, Unit Operating Agreerent for the
Development and Operation of the Santa Clara Unit ..., March 30, 1973.

46. Ibid., p. 3.

47. Ibid.,-p. 10.

48. Exxon Company, USA, "Chronology of Exxon's Efforts to Develop the Santa
Ynez Unit," 1976. (An information leaflet, one page.)

49. Personal communication wi th representatives from Getty, Mobil, Phillips,
Chev ron, and Arco; variousdates between July 1, 1976, and August 18, 1976.

50. The Getty-Gaviota discussion is based primarily on an on-site interview
by Allan Lind, with E. W. Mathisen, Operating Superintendent, Pipeline District,
Getty Oil Company, July 8, 1976.

51. This analysis is based on personal communication to Allan Lind by Darrell
Warner, Exxon Company USA; Jack Hundley, Arco; Coastal Commission staff and the
records of pertinent Coastal Commission hearings; Santa Barbara County staff; and
the various EIRs published to date on the three separate projects.

52. Dames and Moore, Draft EIR, Proposed Dos Pueblos Marine Terminal, 1976,
pp. 11-1, 11-5.

53. Minutes, Hearing of the Board of Supervisors of the County of Santa
Barbara, State of California, September 2, 1975.

54. Appeal No. 163-75 (Platform Holly), California Coastal Zone Conservation
Commission, October 1, 1975.

55. Appeal No. 216-75 (Exxon), California Coastal Zone Conservation Commis-
sion, March 3, 1976.

56. Ibid.

543

57. Exxon Corporation, "Issue Analysis (Avoeal No. 216-75) for the Calif-
ornia Coastal Zone Corporation," October 14, 1975.

58. Analysis based on personal communication, John Herring, Chevron Company,
USA; and Draft EIR, Resumption of Drilling ... From Standard Oil Company of
California Platforms, Woodward-Clyde Consultants, March 1976.
1
59. Woodward.-Clyde Consultants, Ibid., p. 1-21. The report inditates that
24 out of the previous 27 tanker calls, or M.8%, involved deliveries to Chevron's
El Segundo refinery; the balance had as their final destination Chevron's Richmond
refinery in the Bay area. This ratio of deliveries to southern vs. northern
California refineries is thought to be indicative of the tranSDortation economics
for crude o,il produced in the Santa Barbara Channel.
60. Analysis based on site visit and personal communication to Allan Lind, by
Richard Voils, Western Producing Area Projects Manager, Mobil Corporation, July 28, 1976.

61. Title 30 -- Chapter II, C.F.R. Part 250.68.

62. PR C, Division 20. California Coastal Act, section 30108.

544

APPENDIX A

According to Enzer, the following plan was suggested to a Deoartment of
Interior study group by Exxon in 1974 as one alternative for future exoloratorly
operations in OCS frontier areas. The objective was to maximize the rate at
which frontier areas could be leased and explored within projected industry
equipment limitations. According to West Coast Exxon reDresentatives, this
plan does not.-represent an official position of,Exxon Company, USA.

0 U T L I N E 0 F A M A.N D A T 0 R Y U N I T I Z A T 1 0 N P L A N

1. Industry would nominate tracts for sale as they do now. However, they
would also be required to submit an outline of the major structures in the area.

2. The Department then selects tracts for sale and designates exploration
units which conform to the major structures. A complicated faulted structure
may be partitioned into several units.

3. As a condition of the sale, the Department would stioulate that all
tracts purchased in each unit will automatically be part of an exploratory unit.
The operators would submit a unified exploration plan to the USGS, which will be
reviewed with the objective of minimizing the number of exoloratory wells re-
quired to evaluate the structure.

.4. The lease owners-would then agree on an operator to drill the explora-
tory wells at the specified depths and locations. After the initial drilling
program was completed, the'operators, with agreement by the USGS supervisor,
would have the options of dissolving the unit, conducting further exploration
of the unit, or moving into a development phase on either an individual lease
basis or on a unit basis. At this point some of the operators would have the
option of dropping out of the unit and letting the remaining operators continue
as a subunit.

The main operating features of the plan are:

a. the Department would stipulate in advance that the costs of the explora-
tion program would be shared on a surface acreage basis;
b. the agreement would provide that@a1essee may be relieved of an obliga-@
tion to participate in the initial exploration proaram by assignment of
his lease to other operators in the unit or surrender of the lease if
none of the remaining operators accepts an assignment;

C. as long as the operators are diligently oursuing exploratory or develon-
ment operations under an.approved plan, the leases would be held beyond
the primary term;

d. the Department would specify a maximum time for submission of the detailed
exr)loratory.plan by the operators;

e. the unit agreement should permit an oDerator who feels that his tract has
not been adequately evaluated to drill a non-consent well at his own
@expense without forcing him out of the unit; and,

f. lease owners should be allowed to negotiate participation in production
based on an oil and gas in-place factor under their respective tracts
with adjustments for the difference in the value between oil and qas.

The plan is 5aid to have the following advantages:

a. it requires no change in legislation. Its mandatory unit features
insure that exploratory plans.will be?designed to evaluate entire
structures rather than individual leases. This will tend to optimize
the number of exploratory wells drilled. However, it also provides
industry sufficient flexibility to insure'that the structures will
be,fully and adequately evaluated;

b. it achieves about the same efficiencies as leasing large blocks or
entire structures without forcing smaller comnanies to compete for
large blocks; and,

c. while it does not mandate unitization of development and production,
it will tend to strongly encourage this.

The plan is recommended for use in frontier areas, such as the Atlantic, Gulf
of Alaska, and California Outer Banks. It is not recommended for drainage:
acreage or where leases already exist as in the Gulf of Mexico and Santa.Barbara
Channel.

E V A L U A T 1 0 N 0 F T H E B E N E F I T S

After being asked to be more specific as to the potential savings in rig
years such a plan might entail, the sponsoring comr)any provided the following
examples.

Consider a prospect which underlies ten tracts. Exploratory drilling re-
quirements are estimated assuming first that a hypothetical discovery with eight
tracts having-productive results, and second that the entire structure is dry.
Obviously, the number of wells required to evaluate a structure adequately is
highly deoendent on its geologic conditions. However, some average data are
available. The National Petroleum Council (U.S. Energy Outlook: Oil and Gas
Availability, 1973, P. 363) states that between 1954 and 1970 an average of 2.4
exploratory We-11s per tract of 5,000 acres were drilled in offshore regions.
This is an average for dry and productive tracts. The average is heavily influ-
enced by the offshore Louisiana area with its relatively shallow water, low
drillinq costs, and large number of viercement salt dome prospects. A somewhat
reduced exploratory density should be exnected in high-cost frontier areas.
Table Al compares the drilling requirements for the ten-tract prospect assumino
eight tracts productive under individual lease and unit oDeration.

If all ten tracts are purchased by ten.separate operators and no data are
shared or joint wells drilled, an estimated 24 wells or 2.4 per tract would be
required to define the discovery and select platform sites. This would-require
2.6 rig years-over an estimated four-year period, and cost industrv about-
$38 million.

546

TABLE Al:
TEN TRACTS EIGHT PRODUCTIVE'

INDUSTRY ESTIMATED TIME
COST FOR EXPLORATION
WELLS (1) RIG YEARS (2) MM$ (3) PHASE

INDIVIDUAL LEASES
TEN OPERATORS 24 2.6 38.4 4 years

FRONTIER. AREA
UNITIZATION 15 1.6 23.3 2 years

SAVINGS 9 1.0 15.1 2 years
(38%) (38%)

(1) Takina the historical averaqe of 2.4.wells as above average for future frontier
exploration.
(2) Based on 40-day, 12,000-foot wells.
(3) Based on $1.6 million/well.

Under the mandatory exploration plan, it is estimated that only 15 wells would
be required one per tract plus five additional wells on the eiqht Productive tracts
to.define i@itial platform 'sites. This results in about a 40%"saving in wells and
rig years, and completion of the exploratory phase Jn an estimated two years. at a
$15 million.saving to industry.

Table A2 compares the exploratory requirements for this same prospect assuminq
it is dry.

TABLE A2:
TEN TRACTS ALL DRY

INDUSTRY ESTIMATED TIME
COST FOR EXPLORATION
WELLS (11 RIG YEARS (2) MM$ (3) PHASE

INDIVIDUAL LEASES
TEN OPERATORS 15 1.6 24.0 2.5 years

FRONTIER AREA
UNITIZATION 10 1.1 15.5 1.5 vears

SAVINGS 5 .5 8.5 1.0 years
(33%) (33%)

(1) Takina 1.5-wells per tract.as below the average for future frontier exploration.
(2) Based.on 40-day, 12,000-foot wells.
(3) Based-on $1.6 million/well.

36-76658 547

Under individual lease exploration, an estimated minimum of 1.5 wells per
tract or a total of 15 jqoUld be required. Under mandatory exploration, about
30% fewer wells and rig years are required, resulting in an $8.5 million saving
to industry.

It should-be emphasized that the above analysis represents a judgment of
what savings could be achieved under hypothetical conditions. Actual results
will be highly influenced by geologic conditions, leasing patterns, and economic
factors. For example, if the initial wells indicated an economically marginal
field rather than a clear-cut success or failure, a areater number of explora-
tory wells might be necessary. However, the relative saving of 30-40% under the
frontier area leasing plan is likely to be representative of a wide range of
conditions.*

This last paragraph represents the view df*the sponsor of the plan. No
applicable published or unpublished statistics could be found to check the
estimates by the sponsor of the plan (Enzer, 1974, pp. 10-15).

548

APPENDIX B

The Coastal.Plan considers consolidation in Policy 83c, "Consolidate Drillina,
Production, and Processing Sites":

Petroleum-related facilities and operations shall be consolidated (i.e.,
drilling, production, separation facilities, and support sites shal'l be
unitized -- developed and operated as a unit by a single,company or group
of companies for the benefit of all interested companies -_ or shall be
shared) to the maximum extent feasible and legally Permissible, unless
such consolidation will have adverse environmental consequences and will
not significantly reduce the number of producing wells, support facilities
or sites required to produce the reservoir economically and with minimal
environmental impacts .... The unitization or consolidation requirements
shall apply to (1) all types of offshore platforms; (2) submerged produc-
tion systems; (3) onshore drilling and production facilities;'(4) pipelines;
(5) separation, treatment, and storage facilities; (6) transfer terminals
related to petroleum production; (7) riqhts-of-way for transporting Produced
oil and gas; (8) equipment lay-down areas; and (9) Dort facilities to supply.
and service offshore platforms.

The Coastal Act of 1976 provides for consolidation under Section 30262:

Oil and qas development shall be permitted in accordance with Section 30260,
if the following concerns are met:
(a) The development is Derformed safely and consistent with the geologic
conditions of the well site.
(b) New or expanded facilities related to such development are consoli-
dated to the maximum extent feasible and legally permissible, unless con-
solidation will have adverse environmental consequences and will-not
significantly reduce the number of producing wells, support facilities,
or sites required to.produce the reservoir economically and with minimal
environmental impacts.

Similarly, the Santa Barbara County Planning Commission advocates as a matter
Of policy their preference for consolidation:

Consolidation of facilities on existinq sites or on adjacent land will be
favored as an alternative to the estabiishment of new seDarate sites. 63/

The Department of Interior similarly acknowledges the need for and benefits
derived from coordinated planning that could result'in fewer facilities:

In the past the development of oil production facil'ities in the Santa Barbara
Channel (as in most other areas) has been for each lessee (or qrouD of
lessees).to develop its own Production facilities, pipelines, treatment and
storage facilities, and product transportation facilities. This piecemeal
approach has had the advantages of versatility, ease of modification, and
avoidance of joint-interest projects which are often criticized. It has,
however, resulted in proliferation of.facilities in the area with dUDlica-
tion of efforts and little overall coordination.

Thus an alternative to the traditional piecemeal development is the coordinated
development of all oil production in the Santa Barbara Channel. Such coordi-
nation may result in increased costs and increased environmental impact in
specific cases due, for example, to the longer pipelines or larger facilities

549

required, but it-would result in lower total economic and environmental
costs.

Coordination of efforts and minimization of the number of facilities can be
expected to reduce costs (economic and/or environmental) in the areas of
pollution monitoring and product transportation. For example, if all pro-
duction facilities were concentrated in a few centers, this would contribute
toward the economic feasibility of building a single large pipeline from
these centers to the existing refinery complex in Long Beach. Such a pipe-
line would result in lower transportation costs (if the volume of oil were
sufficient) and would eliminate the danner of oil spills during marine
loading, transportation and unloadinq o@ product. 64/

FOOTNOTES, APPENDIX B

63. Santa Barbara Planning Commission, "Statement of Policy Relative to the
Location of On-Shore Oil Facilities," April 12, 1976.

64. Final Environemntal Statement, Oil and Gas Development in the Santa
Barbara Channel..., USGS, Department of the Interior, Q.n. 1-153 to 155, March 4,
1976.

550

CHAPTER 20

TRANSPORTATION:
CROSSING THE WATERS

The means by whi ch OCS oil and gas are transported from production site to
treatment and refining facilities is, along with planning for and locating essential
facilities, clearly a major determinant of environmental risks and degradation. OCS
tracts are currently selected for lease without adequate consideration of whether
production from the tract can be safely and economically transported in a manner
that minimizes environme 'ntal risks. In declaring leases of a recent Atlantic OCS
lean sale null and void, federal Judge Jack Weinstein held the opinion that the
Interior Secretary had failed to consider the environmental effect of specific,
probable pipeline routes from the OCS and had failed to consider the possible re-
sults of particular tract selectfon on the feasibility and siting of pipelines.

Commitments to clean, air and the preservation of the marine'habitat do not
exclude development of the OCS. But the urgency for development of our energy
resources should not preclude these concerns. Because of these concerns and because
the technology is available and economics would justify such a course, pipeline
transport is in theory preferable to marine vessel transport, and should be given
thorough consideration.

California's concern over transportation issues has focused on the develop-
ment of the Santa, Ynez Unit by Exxon. An analysis of the capital and environmental
costs associated with transportation alternatives available to Exxon appears
in Appendix 5 of this report. The following chapter is a generic discussion of
how oil and gas are transported, factors affecting the mode of transportation sel-
ected, and the benefits and limitations of transportation alternatives. The final
part of the chapter discusses the transportation of oil and gas produced from areas
other than the southern California OCS and the potential for conflict with future
OCS development. This chapter, comhined with the preceding Chapter 19, "Facilities
Planning," are the building blocks upon which Chapter 21," Development Scenarios,"
is based.

551

TRANSPORTATION REQUIREMENTS
OF OFFSHORE CRUDE OILAND NATURAL GAS

The fluids produced from offshore wells contain a mixture of crude oil, water,
and dissolved and/or associated gas. They may also contain amounts of hydrogen sul-
fide, carbon dioxide, and other impurities such as sand. Most existing California
OCS platforms, including those in State waters, are equipped for primary gas-oil
separation and water removal. The crude produced at the platform must be transferred
to a treatment facility to remove emulsified water, gas, and impurities such as sul-
fur. Natural gas separated from the produced fluids goes to a scrubber on the plat-
form to remove additional liquids. The gas is then sent to a low-pressure compressor
where a certain amount of gasoline and LPG (liquid petroleum gas) drop out. For
further removal of water, natural gasoline, LPG, and impurities, the gas is trans-
ferred to a separate treatment facility. In southern California, crude oil and gas
have always been pipelined to onshore processing sites. Only recently have offshore
treatment facilities been proposed.

After crude oil and gas are processed, they must be transferred to refineries
or to a gas company distribution system. In some instances, a certain portion of
the dehydrated gas is returned to the platform for reinjection to maintain reservoir
pressure, or retained at the treatment facility as fuel.

E C 0 N 0 M I C D E T E R M I N A N T S 0 F 0 1 L A N D G A S
T R A N S P 0 R T A T 1 0 N N E E D S

The kinds of transportation available for oil consist of-barging or tankering
and pipelining. Those for gas are pipelining and LNG operations. The factors
considered in selecting the most economically appropriate form of transportation
will also affect the location (offshore vs. onshore) of treatment facilities, if
new facilities are required. These factors include:

1. size and projected life of the oil field;

2. market value of the oil and gas;

3. rate of production;

4. amount of capital investment required for development;

5. operating costs of the system;

6. distance from the field to the receiving point on land;

7. water depths; and,

8. topography of the ocean floor. l/

552

The last three factors involve engineering as well as economic considerations.,
and they influence the route of a pipeline. Pipeline developers seek the route
providing the best combination of least distance from production to onshore treat-
ment facilities, shallowest water,.and least.hazardous terrain.

Another important consideration is the distance between reservoirs and their
distribution within a tract. This distance determines the feasibility of installing
gathering lines from platforms to a common trunk line which then carries production
to treatment facilities. Gathering lines become more practical the closer produc-
tion platforms are to one another and the farther they are from shore. Generally,
sites close to shore yet spread out laterally have individual pipelines to shore.
In such a case it would be more costly to gather the lines into a trunk,line.

The size and projected life of the oil fields and their rate of production are
major parameters used for development scenarios. They ultimately decide the economic
feasibility of the transportation mode to be used. Finally, the amount of capital
investment required for development and the operating costs of the system are
directly affected by the physical-properties of the crude oil. For a discussion of
the capital, operational, and environmental costs associated with tankers and pipe-
lines, the reader is referred to the Santa Ynez controversy in Appendix 5.

0 1 L C H A R A C T E R I S T I C S A S D E T E R M I N A N T S
0 F T R A N S P 0 R T A T 1 0 N M 0 D E S

Crude oil characteristics impose constraints on whichever form of transporta-
tion is used. These characteristics include specific gravity, viscosity, pour
point, wax point, and sulfur content. 21

.Specific gravity is the ratio of the weight of the petroleum product to the
weight,of an,equal volume of water. The specific gravity, or weight of the oil,
is a factor in.pumping requirements. Crude oil is often described in American
Petroleum Institute (API) degrees, ranging from light crude, 400 API rating, to
heavy viscous crude, 140 API.

Viscosity measures the resistance of a fluid to flow.: highly viscous fluids
resist movemen *t-thro.ugh-a pipeline. Viscosity of the oil governs the diameter
and thickness of pipe, in turn establishing the material and -laying costs and
fixing the size and number of pumping stations. The viscosity of crude-oil can-
be reduced by heating or diluting it with less viscous petroleum products such as.
natural gasoline.

Pour point and wax point characterize increasing oil viscosity. The.pour
point of an oil is the lowest temperature at which.oil will flow. The wax point
is the temperature at which gas.within the crude oil begins to "cloud" and
11crystallize.".

Sulfur content in crude oil occurs both as-compounds.(sulfide, sulfates, etc.)
and as hydrogen sul-fide (H2S) gas. Each of these have an@impact on the-disposition
and processing of crudes but at different points in the-total process. Sulfur
compounds are undesirable in oil and must be.reduced to.acceptable levels for a
refinery; hence the choice of destinations for the crude is limite&by refinery
desulfurization capabilities.

553

The presence of H S gas in crude oil directly influences the technical design
and material of a pipeiine-. Crude oil containing as much as 0.05 cubic feet of H2S
per 1000 gallons, is classified as "sour" and, when combined with water, forms a
corrosive fluid which results in the embrittlement of very hard or high strength
steels. Pipelines of relatively low strength steels are thus used to carry sour
crude. 3/ Commingling high sulfur and low sulfur oil reduces the chances of
pipeline corrosion, allowing for the shipment of sour crude without changes in the
design or operation of the pipeline system. H2S gas is often removed from the crude
oil at the production site prior to transfer to processing facilities. "Sweet"
natural gas is used.to absorb the.H,S through direct contact. Platform
treatment reduces H S in oil (or ga5) to levels acceptable for pipeline transship-
ment, but further s?ripping at a processing plant is required before shipping
companies will accept sour crude for tanker transport.

T R A N S P 0 R T A T 1 0 N F R 0 M P R 0 D U C T 1 0 N T-0
P R 0 C E S S I N G S I T E

Processing plants are located as close as possible to production areas to
reduce transportation costs. The costs of transporting unprocessed crude oil by
tanker to processing sites is normally prohibitive because the purchaser pays for
shipment of emulsified waste water and other impurities as well as the crude oil.
Where the transportation costs become too high or if onshore processing facilities
a,re unavailable, oil producers have proposed offshore processing plants, with the
transshipment of the processed crude to refineries by tanker (see, for example,
Santa Ynez.Unit and Santa Clara Unit development proposals).

The choice of whether to process offshore or onshore involves the considera-
tion of many factors, a major one being economics. Platform processing requires
fewer and smaller diameter pipelines to shore than onshore processing since the
waste water is not shipped to shore with the oil and then shipped back to the
platform for reinjection onto the reservoir. Platform space, while expensive, may
still be,less costly than onshore processing, and it may be the only option if an
onshore-site is not available. 4/ But while operating costs of offshore process-
ing -- because of more effective use of manpower-already on the platform --
may be lower than onshore processing for southern California OCS production,
offshore processing, storage, and loading operations remain undesirable because
the risks of oil entering the marine environment are greatly increased and.
because of air quality considerations. NaViqational safety may also be reduced
by additional unnecessary fixed structures in the OCS.

P R 0 C E S S I N G P L A N T T 0 R E F I N E R Y

Fluctuations in crude oil production and demand argue for flexible delivery
systems between processing plants and refineries. Under ideal conditions, both
producer and refiner prefer a pipeline network. Direct pipelines are preferable
because the throughput can be regulated, eliminating the use of tankers and tanker-
related storage requirements at the processing end. A pipeline network can also
link several processing plants with one or more refineries to allow selective
delivery of different crudes or blends of crude as market demand requires. Refiner-
ies are always located close to market areas because of hi-gher transportation costs
past the refining stage.

554

.N A T U R A L G A S T R A N S P 0 R T A T 1 0 N

All natural gas produced on the southern California OCS must be transported
by pip eline from production sites to processing plants for treatment and separation.
Where processing sites are not available or the quantities of gas produced areltoo
small to justify a pipeline, natural gas is flared or reinjected into the underlying
reservoir. Offshore.proc'essing of natural gas discoveries in southern California
waters has not proved economically feasible under current technology.

- Natural gas is transported to gas companies-by pipeline or, in liquefied form,
by cryogenic tankships or tank trucks. A vaporization plant receives the liquefied
gas, vaporizes it with heat from ocean water, then compresses the gas to a high
pressure for entry into the utilities transmission lines.

Liquefaction involves an energy loss and, therefore, is practical and profit-
able only when large natural gas fields are separated from potential pipeline
corridors and at extreme distances (thousands of miles) from customers. Southern
California OCS leases are not remote, given-this context, nor are the expected'
quantities of natural gas of a scope to justify,the costs of such an operation
offshore. Pipelines connecting all leased areas off southern California to main-
land gas company transmission lines appear to be feasible given the advances in
pipelaying technology projected for the next five years.

A remote possibility exists for a floating liquefied natural gas plant
located along the Tanner-Cortes Ridge'. Pipelines, connecting both the North and
South areas, could run along the ridge to the facility where the produced gas.would
be treated and liquefied. In order for a floating LNG facility to be economically
feasible the combined gas production from both the North and South areas would have
.to total 400 million cubic feet per day. Alternatively, volumes of natural gas 'too
small to be pipelined ashore or liquefied, can be converted to methanol at a
floating gas plant,.stored in a moored barge, and then taken to port,by transit
tankers. Industry experts have concluded that a production rate of 35 million cubic
feet per day offshore production of liquefied petroleum gases is a realistic
concept. 4a/

POPCO

The Pacific Offshore Pipeline Company (POPCO), a wholly owned subsidiary of
Pacific Lighting Company, has proposed an innovative idea: buy as much
OCS natural gas as possible directly at the platform and construct the gathering
system itsOl@ as a Federal Power Commission (FPC) regulated pipeline company. This
would obviate the cost of transporting the gas from the platform to an onshore
processing plant, while construction of one inteqrated pipeline collection system
would-theoretically be cheaper than numerous spaghetti lines. Gas reserves
thought too small to be produced by different operators within a lease area because
of transportation costs, could be economically transported under POPCO's proposed
gathering system, increasing the.supply of natural gas to southern California.

555

HIOS

A similar gathering system is currently under construction in the Gulf of
Mexico to tap gas reserves in the High Island area off Texas.. The High Island
Offshore System (HIOS) will extend 150 miles offshore and have an expected
delivery capacity of 988 MMCF/D of gas. Through expansion and additional com-
pressor facilities, the HIOS system ultimately could handle two BCF/D.
Unlike POPCO, HIOS is a cooperative of five natural gas pipeline and supply
companies. HIOS, however, will carry gas for other companies having interests
in nearby.gas reserves. In addition to the lateral lines being installed to 35
existinq or,planned platforms, double side-taps are being placed at intervals
along 6e 67-mile main trunkline. They will-allow access for future natural gas
production:if new discoveries are made, as appears likely. Gathering lines to.
the trunkline will be constructed separately from HIOS and will be handled by the
major owner of each line, with generally two or more partners involved. 5/

PIPELINES AND PIPELAYING

C 0 S T 0 F C 0 N S T R U C T I N C R U D E 0 1 L P I P E L I N E S

Based on the actual costs of existing.onshore pipelines, the costs of pipe
and installation usually constitute over 70% of the investment required
to construct an onshore.pipeline. Other average costs for onshore pipelines are:
land (.3%),'right-of-way (2.3%), pipe equipment,(8.7%), storage tanks (5.2%),
delivery facilities (.7%), and miscellaneous appurtenances (1.3%). 6/ Table I
gives the range of pipeline construction cost per mile in 1975 for various diameters.
In highly urbanized areas of southern California, onshore pipeline'costs.will differ
somewhat from these estimates.

As can be seen from Table 2, offshore pipelines may cost two to ten times as
much as same-diameter onshore pipelines, depending on the distance,and the water
depths encountered, the latter being the chief consideration. As depth increases
pipelines require thicker walls for added strength and reduced buoyancy. An increase
of 3/32" in the thickness of the wall of a 30-inch, bare, high-strength pipe raises
the costs some $50,000-per mile, or about $90,000 per mile with a 1/8-inch increase
in wall thickness on a 40-inch line. Also more sophisticated and expensive pipe-
laying equipment is required in deeper waters, with. consequent increases in
installation costs. 7/

TABLE 1:,
ONSHORE PIPELINE CONSTRUCTION COSTS/MILt FOR 1975

RANGE'
DIAMETER
(INCHES)' LOW HIGH
12 t 44,909 $ 52,249
16 45-001 121,922
20 101:674 155,982
24 130,939 139,833
30 179,445 414,866

Source: "Pipeline Economics," Oil and Gas Journal, August 18, 1975, pp. 64-82.
556

TABLE 2:
COMPARISON OF SELECTED ONSHORE AND OFFSHORE PIPELINE CONSTRUCTION COSTS/MILE

ONSHORE OFFSHORE
DIAMETER LENGTH YEAR DIAMETER LENGTH YEAR
(INCHES) (MILES) COST/MILE BUILT (INCHES) (MILES) COST/MILE BUILT
10 10.3 $ 59,938 1974 10 10 $531,472 1.972
12 6.5 44,909 1.973 12 5.1 346,999 1973
16 17.3 50,625 1974 16 16.5 202,184 1973
24 30.7 139,833 1972 24 32.5 306,546 1972

Source: "Pipeline Economics," Oil and Gas Journal, August,18, 1975, 64-82.

.F L E X I B I L I T Y I N P I P E L I N E C A P A C I T Y
The throughput, or capacity, of an existing natural gas or crude oil pipeline
is limited to the maximum allowable working stress of the pipeline walls, fittings,
and valves. In some cases, capacity can be increased by replacing an existing pump
with a larger one or by adding,new pumps on the line. A line is normally designed
to handle an initial throughput but with capability for increased capacity by the
later addition of more pumping stations, as required.

The factors to be considered in designing flexibility into a pipeline are
the diameter of the pipe, its thickness and quality (which set the maximum safe
pressure), and the spacing and number of pumping stations. For example, a 36-inch
crude oil pipeline once proposed by Socal between Estero,Bay and Richmond was
designed to accommodate throughput rates of 340,000, 420,000, or 570,000 barrels
per day, depending on whether two, four, or five pumping stations were put into
operation.

The viscosities of fluids to be pumped through the line present another
variable for determining the thickness of pipe wall 'and the horsepower require-
ments of the pump. Crudes with different viscosities move through pipelines
@differently; a pipeline designed to accommodate the maximum throughput of a highly
visco.us crude could conceivably manage an even greater throughput of a less viscous
fluid, either by batching or by commingling crudes of varying viscosities. Heaters
can also be added-to a pipeline to reduce viscosity and increase flow.

Every pipeline has a maximum throughput, and some pipelines do indeed reach
design capacity in terms of the number of pumpinq stations, heating plants,-and
throughput. If peak production.rates are expected to be quite high, it may be more
economical to build a second parallel line than to attempt.to design for a later
increase in the number of pumps and heaters. Ultimately, pipeline capacity is a
function of the characteristics of the crude.

P I P E L A Y I N G C A P A B I L I T I E S

The printipal problems' of offshore pipelines are water depth and pipe size
(diameter and wall thickness).. The greater the depth, the thicker the wall must
be to resist the bending stresses placed on the*pipe. The thicker-walled pipe,
however, adds weight and thus increases the bending stresses. Pipe diameter is a

557

function of throughput. Large finds of recoverable reserves require larger pipe
diameters,'and this also increases bending stresses on the pipe.

Dramatic improvements in offshore pipelaying technology have helped in over-
coming the previously imposed limits of water depth and pipe size. Depths of 200
feet were once considered the upper limit for layin a pipeline of any size.
Recently, however, a barge (Brown and Roots Bar 347? has been constructed capable
of laying a 36-inch pipe in water 1,100 feet deep., 8/

The maximum depth of pipelines currently in operation is 600 feet (in the
North Sea); this depth will be increased to 850 feet when Exxon completes plat-
form Hondo in the Santa Barbara Channel. Experimental pipelines have been
installed at depths of 1,000 and 1,200 feet. A pipelaying ship designed with a
capability to lay pipe at a 3,000-foot depth is currently under construction. 9/

The greatest depth within any lea sed tract off southern California is 2,500
feet. Gathering lines linking all leases and central gathering stations would
encounter no greater depths, while gathering stations themselves can be located
in depths of less than 850 feet for all OCS lease areas. Trunklines.connecting
the gathering stations with the mainland can avoid depths greater than 1,600 feet.

Proposed tracts for Lease Sale #48 in the southern California OCS, however,
would involve depths approaching 6,000 feet. Shell Pipeline Research and Develop-
ment Laboratory is conducting investigations into pipelining in depths to 3,000 feet
and is looking into the feasibility of extending this capability to 6,000 feet. 10/
The trend of recent developments in pipelaying equipment and the goals being set-
by industry-sponsored research programs indicate that all leased areas off southern
California,can be serviced by on-bottom pipeline within five years.

C A L I F 0 R N I A ' S 0 N S H 0 R E C R U D E 0 1 L
P I P E L I N E S Y S T E M

Little is known about the crude oil pipeline network in California; no public
agency has mapped all the crude oil pipelines, let alone determined their ownership,
current throughput, surplus capacities, costs, or conditions of use. Some informa-
tion has become available in these areas as a result of the Joint Industry/Government
Working Group's efforts to determine the feasibility of land pipeline transportation
of Santa Barbara Channel and Elk Hills crude oil production to replace tanker
operations.
Figure 1 shows the known main pipelines distributing crude oil to the state's
three refinery centers -- the San Francisco Bay Area, the San Joaquin Valley, and
the Los Angeles Basin. This crude oil transportation system is comprised of six
major pipeline corridors:

1. the lower San Joaquin Valley to Los Angeles Basin;

2. the valley to the San Francisco Bay region;

3. the Ventura area to the L.A. Basin;
4. a.highly integrated and complex network (over 1,000 separate pipelines)
in the L.A. Basin moving local production and crude delivered from the
San Joaquin Valley, Ventura,.Los Angeles, and Long Beach Harb ors to the
various refineries in the basin;

558

Figure 1

SAN
FRANCISCO
.,-..:BAY AREA

KETTLEMAN -
C ALINGA
REA

Estero Bay 0 BAKERSFIELD -
TAFT AREA

Santa Maria.

TEXACO 8"
Ventu
UNION 12"

10"
.0w
LOS
ES somo 3o,;,
ANGEL
BASIN

50 0
01
N MILES

559

5. the central California coast (Estero Bay-and Avila Beach) to the San
Joaquin Valley, permitting shipment to or from the coast and to the bay
region from Estero Bay; and,

6. the Four Corners Pipeline, the only designated common carrier line in
California, linking the Los Angeles Basin with the Four Corners area.

In addition, at each producing area there are numerous gathering lines connected
to the main trunklines.

Table 3 was compiled from information supplied by trunk line operators in
response to a memo from the Joint Industry/Government Working Group chairman
requesting data regarding the physical properties of the pipelines and crude oil
being transferred. Excess capacity within each of the lines listed in Table 3
will determine the feasibility of alternate inland routes for crude oil trans-
portation of southern California OCS and/or Elk Hills production.

TABLE 3:
PRESENT AND POSSIBLE PIPELINE CAPACITIES*

SAN JOAQUIN VALLEY TO THE SAN FRANCISCO BAY AREA

PRESENT
CAPACITY MAXIMUM CAPACITY
COMPANY AND SIZE BBLS/DAY BBLS/DAY
Chevron 1811 83,000 96,000
Getty 2011 105,000 200,000
Union 1611 59,500 70,000
247,500 366,000

SAN JOAQUIN VALLEY TO LOS AINGELES BASIN

Arco 1411 68,000 95,000
Mobil 1011 50,000 50,000
118,000 145,000

SAN JOAQUIN VALLEY TO AVILA

Union two 8" 48,000** 48,000**

SAN JOAQUIN VALLEY TO ESTERO BAY

Chevron 1211 60,000 60,000

TOTAL 473,500 619,000

*Capacities are based on crude oils produced in the San Joaquin Valley having
gravities varying from 140 API (heated) to 250 API (unheated).

**Anproxi.mate; exact fiqures not available.

Source: Letter from John Messer, State Lands Division, to Al Reynolds, Chairman,
Joint Industry/Government Working Group, regarding Pipeline Strategy Report -- San
Joaquin Valley Trunkline Capacities and Production Trends, April 14, 1977.

560

Table 4 summarizes the apparent present surplus capacity of trunk lines
leaving the San Joaquin Valley. Estimates of-the maximum surplus capacity that
may be developed with additional pump and heate.r stations to accommodate viscosity
and pressure limitations-Qf the existing lines show that the present
surplus capacity of 70,500 B/D can be expanded to 216,000 B/D. These figures are
based on the assumption that San Joaquin Valley production (except the Elk Hills
fields) will stay at the present rate.

TABLE 4:
AVAILABILITY OF SURPLUS PIPELINE CAPACITY

BBLS/DAY
a. Current crude oilproduction in the San.Joaquin Valley,
including Elk Hills 525,000
b. Current crude oil consumed by San Joaquin Valley refineries 122,000
c. Crude oil leaving by pipeline (a. minus b.) 403,000
d. Present pipeline capacity 473,000.
e. Present surp.lus capacity (d. minus c.) 70,000
f. Maximum pipeline capacity 619,000
g. Maximum surplus capacity (f. minus c.) 216,000

Source: Letter from John Messer, State Lands Division, to Al Reynolds, Chairman,
Joint Industry/Government Working Group, regarding Pipeline Strategy Report --
San Joaquin Val1ey Trunkline Capacities and Production Trends, April 14, 1977.

CALIFORNIA'S ONSHORE PIPELINES ARE PRIVATE

Once crude-oil is brought ashore and treated, it is delivered to
refinery centers by either pipelines or tankers. California is exceptional among
oil-producing states in that all but one of the onshore crude oil pipelines in 6e
state'are privately owned and-nearly all are operated by major integrated companies.
Integrated-companies maintain control,of their oil from the time it leaves the ground
until it is sold as a refined product.

Crude oil carried in private onshore pipelines, however, is nothecessarily
produced by the parent company owning the lines, nor is it used in that company's
refineries. Essentially these pipelines.are operated like common carriers, but
the pipeline company purchases the crude.oil from the producing company at one
end of-the line,-.carries it to the other end, and then resells it (possibly to the
ini.tial owner or to a competitor). Operators of private pipelines thereby avoid
common carri.er status in that they transport their own crude oil. This poses
.certain limitations on the flow of offshore crude oil or any crude oil in that pri-
vate pipeline owners regulate the costs of the crude oil moving through them and
@can control access as well.

The major oil companies in California prefer private ownership of crude oil
pipelines beca@use it gives them an added measure of control over crude oil marketing.
Transportation costs charged by common car rier oil pipeline companies are regulated
.by the Interstate-Commerce Commission OCC). Tariffs for privately owned crude oil
pipelines are-not regulated, allowing-the pipeline company to set its own price for
purchasing crude and reselli,ng it.

561

In a report of the Joint Committee on Public Domain on "Crude Oil Pipelines
in California" (October 1974) the private carrier pipeline system was described
as functioning in clear defiance of the State constitution. The report went on
to say:

The major oil companies control the CAlifornia crude oil market
by their ownership and control of the crude oil pipelines. This
control artificially depresses prices paid to independent pro-
ducers and restricts the supply of crude oil to the independent
refiners. Starving the independent refiners inhibits competition
at the retail products level and results in too-high prices at
the gasoline pump. Llj

All attempts by the-Legisl.ature and the Public Utilities Commission to-elimi-
nate the control private pipeline companies exert over independent producers and
refiners have failed.

A common@carrier pipeline is desirable to carry.OCS production from the Santa
Barbara Channel area to Los Angeles refineries because all companies would be
guaranteed access at a regulated price. Transmission costs would be competitive
with other means of transporting crude oil, if not cheaper. Although common
carrier pipelines are desirable, they are not absolutely essential. Channel pro-
ducers could form a private pipeline consortium that would build and operate a
pipeline in the same manner as a common carrier pipeline, and with some assurance
given that future producers not part of the original consortium would be allowed
access. A common carrier pipeline, however@ would eliminate the many problems
encountered in trying to get private producers to cooperate and enter into a pipe-
line agreement. The problem of anti-trust allegations would be.avoided as well.

S 0 U T H E R C A L'I F 0 R N I A '. S 0 N S H 0 R E N A T U R A L
G A S P.I P E L I N E S Y S T E M

Natural gas pipelines are regulated by the State Public Utilities Commission
and are well documented. Several natural gas companies serve the southern Cali-
fornia coastline from Point conception to San Diego. Natural,gas t@ansmission and
trunk lines operated by the various gas companies are within five miles of any
landfall between Point Conception and-the Mexican border.. Engineering feasibility.
studies may be required before OCS natural gas could be.transshipped through'.these
lines, although many-of them are known to have the capacity to carry OCS natura1
gas production. New pipelines may be required if existing lines are not capable
of further increases in throughput..

MARI NE'TRAN SPORT
Crude oil produced from the Long Beach-to-Huntington Beach offshore area is
delivered to Los Angeles refineries by.pipeline, while that produced from the-
Santa Barbara Channel is delivered to refineries'by tankers or barges as well as
by pipelines. Tankers are.loaded at marine terminals located within the Channel,
and the crude is then taken.to refineries in Los Angeles or the San Francisco Bay
area. The largest.-Cerminal.s are at Ventura.and are operated by Getty and Union.
Three pipelines-also directly.connect.ventura with Los.Angeles refineries
(see Figure 1). A ten-inch pipeline, owned by Shell Oil Company, has an estimated.
t[7roughput'capacity of 51,000 B/D. Union operates an eight-inch line, with.an

562

Exxon Baltimore, a 48,000 DWT tanker suitable for the
Alaskan trade as well as coastwise traffic for transporting
southern California offshore production. A tanker of approximately
this size is proposed to be used by Exxon as an offshore storage
and terminal (OS&T) facility for the Santa Ynez Unit (see Chapter 22).
(Photo courtesy of Exxon Company, USA.)

37-76658 563

18,000 B/D capacity, from Ventura to Torrey Canyon from which point a 12-inch line
with an estimated 48,000 B/D capacity extends to Los Angeles. Texaco operates an
eight-inch line running east to Fillmore, then south to Newhall, just above Los
Angeles, where it connects with other pipelines. The Ventura-to-Fillmore section
has an 18,000 B/D capacity, and the Fillmore-to-Newhall line, 33,000 B/D. .12/

A 22-inch pipeline operated by Mobil brings crude oil from treatment facili-
ties south of Rincon Point into the Ventura Marina where it ties in with the Shell
and Texaco pipelines. The Mobil 22-inch line is capable of carrying 170,000 B/D.
The total capacity of all the lines running out of Ventura to Los Angeles is only
87,000 B/D. When the lines are operating at maximum capacity, tankers are used to
deliver crude from Channel producing areas north of Rincon Point and from the
marine terminals at Ventura. Tankers are also used between the Channel and San
Francisco Bay area-refineries because the two areas are not now linked by pipelines.

V E S S E L T R A F F I C P A T T E R N S I N
S 0 U T H E R.N C A L I F 0 R N I A

The miajority of foreign and domestic merchant vessel traffic in southern
California is confined to legally established vessel traffic lanes from Point
conception to south of the Los Angeles and Long Beach Harbors complex. A study
in progress by the U.S. Coast Guard Research and Development Center indicates
that traffic within the lanes in the Santa Barbara Channel is as follows:

Northbound Southbound
Between Point Conception and 6.6 6.0
Port Hueneme 13/ Vessels/Day Vessels/Day

A common traffic pattern for handling crude oil production in the Channel area has
evolved. A tanker originating in Los Angeles, Long Beach, or El Segundo moves
via the northbound lane to the Channel, leaving the lane to make calls at the
Channel marine terminals, and returns by way of the southbound lane to the Harbors
or El Segundo for offloading.

From Port Hueneme to the Los Angeles/Long Beach Harbors, traffic within the
shipping lanes increases sharply with the influx of vessels of foreign origin.
and destinations entering or leaving midway between Port Hueneme and Los Angeles/
Long Beach Harbors. Estimates of vessel traffic within this area were compiled by
Tetra Tech, Inc., from unpublished data supplied by both the U.S. Coast Guard and
the Army Corps of Engineers for the year 1975. 14/ The following numbers include
vessel movement to and from the four marine te.rminals at El Segundo and the Los
Angeles/Long Beach Harbors.

Northbound Southbound
Between Port Hueneme and 12 10.6
Los Angeles/Long Beach Harbors Vessels/Day Vessels/Day

Tetra Tech's data for traffic within the Santa Barbara Channel for 1975 showed
6.2 vessels/day northbound and 4.8 vessels day southbound. Comparing these figures
with current data supplied by the Coast Guard for the Santa Barbara Channel shows an in-
crease of 6.5% in northbound traffic and 25% in southbound traffic since 1975. Assuming

564

a similar increase over the same period for traffic between Port Hueneme and Los
Angeles/Long Beach, estimated vessel traffic for 1977 would be as follows:

Northbound Southbound
Between Port Hueneme and 12.8 13.2
Los Angeles/Long Beach Harbors Vessels/Day V6ssels/Day

PROJECTED VESSEL TRAFFIC INCREASES CAUSED BY SOUTHERN CALIFORNIA OFFSHORE CRUDE
OIL PRODUCTION

If an onshore pipeline is not constructed to deliver Santa Barbara Channel
production, as many as 40 new round trips per month can be expected by 1980. New
production from So *uth Elwood, Summerland, and Carpinteria offshore fields could
add seven round trips per month (assuming development as projected in the related
EIRs). The Santa Ynez Unit could add 11 round trips per month (assuming 60,000 B/D
ultimate production and an average cargo size of 175,000 barrels). New production
from Platforms C and Henry could add five round trips per month from the Union
marine terminal at Ventura (assuminq all new production is transshipped through
that terminal); and new production @rom tle Santa Clara and Hueneme Units could
add ten round-trips per month. The peak round trip estimates occur at different
times between 1979 and 1983 and therefore do not add up to the estimated total of
40 round trips projected to occur in 1980. If pipeline options are not constructed
for the Outer Banks areas, an additional 40 round trips per month, or 1.3 round
trips per dky, for all three areas could occur in 1983, assuming 150,000 B/D are
produced from the Outer Banks.

A V I G A T 1 0 N A L S A F E T Y

In the late 1960s and early 1970s the Coast Guard, the Army Corps of Engineers,
the Department of the Interior, the U.S. Navy, and shipping and offshore oil inter-
ests joined together in developing an effective Vessel Traffic Separation Scheme
(VTSS) in certain areas off the California coast to provide a safe and unobstructed
navigation route for deep-draft vessels. By separating vessel traffic and allocat-
ing the sea space needed for safe entry and exit of vessels at busy ports, the risk
of collisions and environmental damage could be minimized. Vessel traffic
schemes were established for San Francisco, Santa Barbara Channel, Santa Monica
Basin, western approaches to Los Angeles/Long Beach Harbors, and most recently the
southern approaches to Los Angeles/Long Beach Harbors through the Gulf of Santa
Catalina.

The Pacific Merchant Shipping Association (PMSA) has expressed deep concern
over the need to keep the vessel traffic lanes clear of oil drilling structures.
In the Santa Barbara Channel, 20 of the 65 active leases are intersected by the
designated shipping lanes; and seven of the 13 San Pedro Bay leases intersect the
shipping lanes on the southern approach to Los Angeles/Long Beach Harbors (see
Figures 2 and 3). Most commercial vessels entering or leaving San Pedro Bay use
these lanes. In 1976 the U.S. Coast Guard recorded an average of five vessels
per day northbound and 3.5 vessels per day southbound through the traffic lanes
in the Gulf of Santa Catalina. These estimates refer to passenger or cargo vessels,
tankers, seagoing barges, and Navy vessels with drafts more than 18 feet; they do
not indlude smaller barges, commercial or sport fishing boats, pleasure boats,
tugs, research vessels, Coast Guard vessels, or the Catalina ferry. Over 600 of
these smaller vessels traverse the waters between Los Angeles and Santa Catalina
daily.

565

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VESSEL TRAFFIC LANES:
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Vessel Traffic Lane Ap.1 H17 flald
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LOS ANGELES
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VESSEL TRAFFIC LANES: Figure 3
SAN PEDRO BAY

FLi Leased Area

Vessel Traffic Lane
wwwwwwwW
11111111116. Precautionary Zone 10 1315 110 KILOME'
10 13 15 110 IVI I Fc, 5Z
NORTH SCALE 1500.000 DEPTH CURVE,n FAT
567 April 1977 California Governors Office of Plannin d R ... arch
ocs Ph6jECT

The approach to Los Angeles/Long Beach Harbors was difficult even before oil
drilling structures posed new hazards from high traffic density and to sudden fog
common at various times throughout the year. Statistics for tanker collisions show
that 80% occur in coastal or harbor regions, and 82% occur when visibility is poor. 15/
The only recorded collision involving a tanker in the Santa @arbara Channel occurred-in
heavy fog just after midnight. These conditions, together with the potential for
collisions between commercial and public vessels and oil structures, formed the moti-
vating force behind the development of traffic lanes.

The ships that will be used in the near future for transporting crude oil and LNG
to California ports will be much larger, faster, and less maneuverable than vessels
currently operating off the coast. Energy-related vessel traffic will be a larger
component of vessel congestion as well. These developments greatly compound the need
for clear traffic lanes. J,

The Army Corps:of Engineers is responsible for the issuance of drilling permits
on the OCS. At the request of the Bureau of Land Management, the Corps issued drilling
permits for the. seven leases in the San Pedro Bay intersecting the southern approach
to the Los Angeles/Long Beach Harbor, although the area had already been set aside,
with approval of the U.S. Coast Guard, for vessel traffic. The Corps has ignored
warnings from the Pacific Merchant Shipping Association that drilling in these par-
cels could present a navigational hazard. It is PSMA's position that indiscriminate
drilling in waters necessary for safe passage of vessels would undermine the entire
concept of traffic lanes and open the door to further encroachment of critical sea
space near congested traffic routes off California's coast. Encroachment also places
the shipowner in a precarious position regarding his liability in the event of a
collision with oil drilling vessels, barges, or permanent structures. There are no
recorded ship-platform accidents for the California OCS. However, during the period
from July 1, 1962, through June 30, 1971, the Coast Guard recorded 24 incidents of
collisions between vessels and fixed platforms in the Gulf of Mexico. Eight of these
accidents involved vessels over 1,000 gross tons. 16/

Moving the VTSS is not the solution to avoiding collisions. Use of the VTSS is
recommended, not required; the present scheme, however, reflects customary and his-
toric routes for vessels approaching and leaving southern California.harbors. Any
move of the scheme in the Gulf of Santa Catalina would interfere with the recreational
boating traffic between the mainland and Santa Catalina. Exploratory and development
facilities resulting from future lease sales will have the possibility of interfering
with the VTSS no matter where it is located.

The Coast Guard has urged the Corps to establish a safety fairway across the
Santa Catalina VTSS (southern approach to the Los Angeles/Long Beach Harbors).
Safety fairway designation would prohibit the installation of any fixed structures in
the vessel traffic lanes, including platforms or movable drilling rigs. Such a move
,would not preclude production from oil and gas reserves in OCS tracts intersecting a
safety fairway, since slant drilling operations could be used. Standard Oil of
California,and Shell Oil have encountered oil-bearing sands in their San Pedro Bay
tracts within the Santa Catalina VTSS, at depths below 2,900 feet. If other San Pedro
Bay prospects lie at equivalent depths, then all tracts could be explored from a dril-
ling vessel lying outside the 5,280-foot-wide traffic lanes, using slant drilling at
an angle of less than 45 degrees. 'Such slant drilling operations are well within the
oil industry's present capability.

The Corps has issued a public notice (Federal Register, Vol. 41, No. 198,
October 12', 1976) establishing rules and regulations for permits for exploratory
drilling operations in the Pacific Ocean at the Gulf of Santa Catalina. The proposed
regulation would establish an eight-nautical mile buffer between an exploratory

568

vessel in a lane and the nearest fixed structure in the same direction of traffic,
and a 3,000-yard buffer in all other directions. There are no restrictions pro-
posed on the siting of exploratory vessels in the separation zone between the lanes.
This can only be regarded as a gesture by the Corps and a rather small one since it
applies only to exploratory drilling in the Gulf of Santa Catalina. The entire pro-
cess of establishing regulations would have to be repeated for guidelines applicable
to fixed production pl*atforms, and for areas other than the Gulf of Santa Catalina..
It may be years before such final regulations are adopted. In the interim, the
efficacy of the Vessel Traffic Separation Schemes in the Santa Barbara Channel and
Gulf of Santa Catalina will' have been seriously impaired by fixed production platforms.

ENVIRONMENTAL RISKS: TANKERS VS. PIPELINES

Statistical comparisons between tankers and pipelines, in terms of oil spill
probability, consistently favor the use of pipelines for transporting south*ern
California OCS production. Oil spill potential is believed.to be a function of
the opportunities for spills to occur; the opportunities are clearly greater for
tankers., Tankers and barges distribute oil to the marine environment in several
wa s: oil discharges from bilge pumiping, ballasting operations, tank cleaning,
y
dry docking, terminal operations, and fallout from exhaust stacks. Aside from
these normal operations and accidental releases of cargo and bunker fuel, tankers
and barges are exposed to numerous risks that result in oil spills. For example,
incidents can occur as a result of structural failures, rammings, groundings,
collisions, breakdowns, fires, or explosions. Each vessel operating off the southern
California coast faces the probability of one or more of these occurrences. Addi-
tionally, and perhaps most significantly, the loading and unloading of tankers and
barges increases the handling of crude, further raising the number of opportunities
for a spill. Finally, tankers or barges depend more heavily on storage facilities
because of their periodicity, than do pipelines. This storage requirement is
another source of oil spill potential as well.

Marine transport of OCS production involves numerous opportunities for mishap and
disaster that are multiplied with each tanker or barge visit over the entire lifetime
of a producing area. In contrast, pipelines present a singular, albeit constant, risk.
Throughout the history of pipeline usage for crude oil and natural gas transport, both
on and offshore, the incidence of pipeline leaks resulting from structural failure or
installation errors is almost nil. Most pipeline accidents are directly attributable
to external damage o.r rare and infrequent natural phenomena.

Prior to 1970, several pipelines in the Gulf of Mexico were damaged by anchors,
resulting in large quantities of spilled oil. Since then the Bureau-of Land Manage-
ment has required all new pipelines be buried in at least three feet of cover in areas
less.than 200 feet deep. Where pipelines cross shipping fairways and anchorages, they
must be buried at least 10 feet. The Office of Pipelines Safety (OPS) has required
that pipelines be-coated with tightly,bonded, moisture-impervious material to prevent
corrosion. OPS regulations also require continuous line pressure monitoring with some
type of communication system (a built-in alarm or automatic shut-down system), and
regular ins'pection of the pipeline route for leaks and other irregularities.

Most spill factors for pipelines are derived from historical OCS spill data, a
large portion of which comes from OCS operations in the Gulf of Mexico. Such factors,
therefore, have limited-applicability for future OCS development in the Pacific in that
they do not reflect the improvements mentioned above. Had the present regulations
governing pipeline design and placement been enforced at the beginning of offshore pipe-
laying, spill factors for pipelines would be significantly lower than those currently
based on historical performance.
569

Other studies often use worldwide data for selected years to
determine spill factors for tankers. This too results in artificially
high spill projections for future OCS transportation activities, depending on
the sample years selected. Tanker casualties in one year could be either abnor-
mally high or low as a single spill like the Torrey Canyon can distort the statis-
tical distribution of spill magnitude. Spill factors from such years do not
reflect the@ vessel traffic situation encountered over the production lifetime of
an area.

In its critiques on the Bureau of Land Management's Draft EISs for Lease
Sale #35, Oil and Gas Development in the Santa Barbara Channel OCS, Dames
& Moore cited several studies based on worldwide data which placed the 4
emission rate for tankers between 127 ppm to 165 ppm of the total oil carried.
These studies also indicated that open-ocean spills (beyond 50 miles) tend to be
over three times as large as those in coastal areas (within 50 miles of land).
Most of the open-ocean spills resulted from structural failures caused by extreme
sea and weather conditions. 17/ Dames & Moore therefore felt that because condi-
tions off the southern Califo-rnia coast were not comparable to those in many parts
of the open ocean,'an appropriate spill factor for the southern California OCS
should be based on casualties within 50 miles of land. The following table com-
pares the Dames & Moore spill factors with those presented in a report by the
Council of Environmental Quality.

TABLE 5:
BARRELS SPILLED PER MILLION BARRELS HANDLED WITHIN 50 MILES OF LAND

SPILL SOURCE CEQ DAMES & MOORE

Tankers 160 88
Pipelines ITO 13

CEQ's rates were derived from historical data and therefore lack assumptions
about improved technology and stricter regulations. Their high emission rate for
pipelines stems from those accidents which occurred in the Gulf of Mexico. Tanker
emission rates were derived with no distinction being made between spills in the
open-ocean and coastal waters. Dames & I'loore's rates incorporated these considera-
tions and therefore are lower than CEQ's. With these allowances, pipelines are
s'afer to use by almost a factor of 7.

Surface transport of crude oil is necessary and acceptable over great distances.
But to use tankers and barges as shuttlecrafts for transporting local production
to separation and treatment facilities, and to refineries, is to risk environmental
harm unnecessarily. This is especially true when pipelines are technically and
economically feasible. Future OCS leasing policy should enhance the economic
adva'ntages of pipeline transportation through tract selection and permit conditions.
The cost of pipeline transport is at a minimum when the pipeline operates continu-
ously at full capacity. Permit condition-s can be used to coordinate the development
of lease areas, optimizing the operating costs of a pipeline. Proper tract selection
is important as well to insure that the amount of recoverable reserves within a lease
area is sufficient to justify the use of pipelines.

570

EXTERNALITIES: ALASKA, ELK HILLS, AND INDONESIA

The future transshipment of Alaskan oil and LNG, Indonesian LNG, and possi
bly of Elk Hills oil could significantly increase the amount of tanker vessel
traffic passing through the Santa Barbara Channel and off the southern California
coast, depending on the final destinations approved for each proposal. Marine
traffic resulting from southern California OCS development will have to merge into
existing traffic flow and contend with the increasing likelihood of vessel
collision. The following discussion gives the projected traffic volumes that
can be expected if onshore receiving terminals for handling Alaskan oil and LNG
and Indonesian LNG are built as planned, and if Elk Hills oil is delivered to
Port Hueneme.

A L A S K A N 0 1 L

Six companies share in the crude oil produced at Prudhoe Bay -- Exxon,
Arco, Union, Phillips, Mobil, and Standard Oil Company of Ohio (Sohio).- Sohio has
a 54% ownership of the crude produced, Exxon and Arco each have 20%, and Mobil and
Phillips have approximately 3% each. Sohio alone has submitted plans for disposi-
tion of the oil in California. The Arco fleet will serve the company's 96,000 B/D
refinery at Cherry Point., Washington, then move south to the Los Angeles Basin.
Shell, which owns a small percentage of Prudhoe Bay crude, plans to move its share
to Shell refineries at Martinez in the San Francisco area and Wilmington in the
Los'Angeles area. Mobil also plans to bring crude from.Valdez to Los Angeles,
where the company has a refinery at nearby Torrance. 18/ Given the lack of infor-
mation about the transport of oil from Valdez to CaliT-ornia ports by the other
Alaskan interests and conclusions about additional tanker traffic off southern
California would be merely speculative.

Sohio proposes to bring 700,000 B/D of Alaskan crude oil to Long Beach. -The
projected tanker fleet is a mix of four 80,000 DWT, three 120,000 DWT, and four
165,000 DWT ships. The crude would be offloaded at a proposed common carrier,
deepwater tanker terminal in the Port of Long Beach. From the terminal the crude
would move through a new onshore common-carrier storage surge facility developed
by Sohio, then be transported to Midland, Texas, by a proposed common carrier
pipeline. If the proposed Alaskan crude oil terminal is constructed in Long Beach
Harbor, all of the Alaskan tanker traffic between Long Beach and Valdez will pass
through the Santa Barbara Channel.

The 11 Sohio vessels alone will be making a total of 267.3 port calls per year
at Long Beach. Should the flow of crude through the Alaskan pipeline be doubled,
Sohio expects to increase its southbound tanker volume to'1,200,000 B/D and add
six 165,000 DWT ships to its fleet. Thus by 1982 a Sohio tanker fleet of 17 ships
could be making 408 annual trips moving between Valdez and Long Beach. 19/

E L K H I L L S 0 1 L

The Naval Petroleum Reserves Production Act of 1976 authorized the develop-
ment of certain national petroleum reserves. The act specifically directs the
Secretary of the Navy to acquire or construct by April of 1979 the facilities
needed to ship not less than 350,000 B/D of crude oil from the Naval Petroleum
Reserve at Elk Hills in the San Joaquin Valley to unspecified marketing terminals.
Several transportation options are being considered:

571

1. Elk Hills to Port Hueneme via.pipeline with further distribution by
tanker;

2. a crude oil pipeline from Elk HIlls to connect with either a Getty,
Union, or Chevron pipeline at Coalinga, using excess capacity as
available;

3. Elk Hills to Redlands via pipeline connectinq to a 42-inch portion of
the proposed Sohio pipeline; and,

4. a railroad/truck tank car system for transport to appropriate marketing
facilities. 201

The most desirable route from a marketing standpoint appears to be the Redlands
connection to Sohio's proposed west-east pipeline. If the Sohio line cannot be
completed by the 1979 date, to which the Navy is committed, it might be necessary
to build a pipeline from Elk Hills to Port Hueneme. The Navy presently holds an
option on an Arco 20-inch gas pipeline extending from the Southern California-
Edison Mandalay Beach steam plant near Ventura to the Cuyama Valley, The Navy would
have to convert the line to carry crude oil and then build two connecting 20-inch
pipelines v- one from Cuyama to Elk Hills, the other from Ventura to a tank farm to
be built at Port Hueneme.

The Navy wharf facilities at Port Hueneme are limited to 35,000 DWT tankers
or smaller because of the maximum harbor draft of 35 feet. Dredging would lower
the harbor depth, increasing the maximum draft vessel that could be accommodated.
If 35,000 DWT tankers are used, it has been estimated that an average of one tanker
every 19 hours would be loading to transport 200,000 B/B through Port Hueneme. 21/
The use of larger tankers would, of course, reduce the number of visits. Alter@n_ately,
if production rates of 350,000 B/D are not achieved (as considered likely), the
number of tanker visits will be less. If Elk Hills production is delivered to Port
Hueneme, vessel traffic through the Santa Barbara Channel, and from Port Hueneme to
the Los An'geles/Long Beach Harbors will increase.

L N G A L A S K A I N D 0 N E S I A

Three major proposals to transport LNG by cryogenic tanker to southern Cali-
fornia for regasification and distribution are currently being considered. Two
proposals concern the transportation of the natural gas recovered from Alaska. The
El Paso/Alaska System proposal would deliver LNG to a loading and receiving terminal
to be built at Point Conception, located at the northern end of the Santa Barbara
Channel. The Pacific Alaska LNG Company proposes to deliver its LNG to a receiving
terminal in the Los Angeles Harbor. The third source of LNG to southern California
involves a proposal by the Pacific Indonesia LNG Company to import LNG from
Indonesia,to Oxnard.

Each of tho three regasification faciliti-es would be constructed and operated
by the Western LNG Terminal Company, with a design capacity of four BCF per day.
Use of the three proposed facilities is to occur in phases until design capacity is
reached. The El Paso/Alaska receiving terminal at Point Conception would expect
308 annual visits from cryogenic tankers. Annual visits to the LNG facility at
Oxnard would start at 75, and at 52 for the Los Angeles site. At design capacity,
each LNG terminal would receive between 425 and 565 tanker visits annually. @2/

572

Clearly, if all the LNG proposals were approved and operating at design
capacity by 1981, future Vessel traffic patterns off the southern California
coast and within the Santa Barbara Channel would become seriously congested.
Again, if LNG terminals were constructed.at Oxnard and/or Los Angeles Harbor,
all LNG deliveries from Alaska and Indonesia would be by way of the Santa
Barbara Channel. If only one LNG terminal is constructed and placed at Point
Conception, the Channel itself will not experience increased vessel traffic
from the importation of LNG.

Given the maximum projection for vessel traffic from each of the sources
discussed above, the following table summarizes the number of daily trips that
could be expected.

TABLE 6:

SOURCE ROUNDTRIPS PER DAY REMARKS

Crude oil from Valdez 1.1 Assumes 1,200,000
to.Long Beach B/D and mean tanker
size of 136,825

Elk Hills oil from Port 1.3. Assumes 200,000 B/D
Hueneme to Los Angeles/ and average tanker
Long Beach Harbors, or size of 35,000 DWT
San Francisco

LNG from Alaska and 3.5 - 4.6- Assumes each facility
Indonesia to Point is operating at design
Conc'eption, Los Angeles/ capacity of 4 BCF
Long Beach, and Oxnard per day

While the possibility of all the-above scenarios developing to maximum
capacity may seem remote, the fact that vessel traffic off the southern California
coast will substantially increase by the year 1981 as a result of energy-related
developments is irrefutable. Measures.have been taken to protect the southern
California coast from unnecessary environmental risks associated with an increase
in vessel traffic. The Commander of the Eleventh Coast Guard District, R. I. Price,
requested that the U.S. Army Corps of Engineers designate as a Safety Fairway the
Traffic Separation Scheme between Point @onception and Point Fermin, thus exclud-
i'ng encroachment by oil production platforms into shipping lanes. The Coast Guard
has also recommended a helicopter surveillance of the Santa Barbara Channel to@
police adherence by all vessels to prescribed traffic lanes. Attention has also
focused on the feasibility of consolidating LNG operations. A consolidated LNG
facility would help to reduce traffic within the Santa Barbara Channel only if
it were located at Point Conception or at a location north of there.

573

FOOTNOTES

1. California State Lands Commission, State Lands Division, Oil and Gas
Development, Santa Barbara Channel -- Southern California OCS, September 1976,
Sec. III, p. 1.

2. Ibid., p. 2.

3. Ibid., p. 5.

4. Letter from L. P. Haxby, Shell Oil Company, to Richard Hammond and Suzanne
Reed, March 11, 1977.

4a. The Oil Daily, June 2, 1977, "Offshore Methanol, LNG Production is
Predicted."

5. Leonard Leblanc, "HIOS Contractors Shoot for November 1 Start-Up,"
Offshore, February 1977, 43-47.

6. Robert C. Ewing, "Pipeline Economics," The Oil and Gas Journal, August 23,
1976, 80.

7. Douglas Bynum, Jr., "Here's a quick, easy method to design a system for
higher efficiency," Offshore, February 1977, 82.

8. Robert C. Earing, "Subsea pipeliners' know-how gets the job done," The
Oil and Gas Journal, January 3, 1977, 48.

9. U.S. Department of the Interior, Pipelines and Outer Continental Shelf
Oil and Gas Production, October 27, 1976, p. 3.

10. Booz-Allen & Hamilton, A Risk and Cost Analysis of Transporting Southern
California Outer Continental Shelf__2@11, for the V.S. Environmental Protection Agency,
July 3, 1975, p. 11-6.

11. Joint Committee on Public Domain, Ken Cory, Chairman, Crude Oil Pipelines
in California, October 1976.

12. Ibid., pp. 56-57.

13. Letter from R. I. Price, Rear Admiral, U.S. Coast Guard Commander, to
Richard Hammond, March 22, 1977.

14. Tetra Tech, Inc., Environmental Assessment Report, Crude Oil Transportation
System: Valdez, Alaska to Long Beach, California, Appendix B, Oil Spill Analysis,
p. B-7.

15. Margaret Cashman, "Tankers will be safer in the future," Ocean Industry,
March 1975, 44.

16. U.S. Department of the Interior, Bureau of Land Management, Final Environ@
.,mental Statement, Proposed 1975 Outer Continental Shelf Oil and Gas General Lease
Sale Offshore Southern California (OCS Sale No. 35), Vol. 2, p. 77.

17. Ibid. , Vol. 3, p. 639.

574

18. Howard M. Wilson, "Beefed-up tanker fleets readied for North Slope oil,"
The Oil and Gas Journal, June 14, 1976, 25.

19. The Port of Long Beach and the California Public Utilities Com@ission,
Draft, Environmental Impact Report, Sohio West Coast to Mid-Continent Pipeline
Project, Vol. 3, Part 3, Sec. 1, p. 5.

20. Ibid., Vol. 3, Part 2, Sec. III, pp. 158-159.

21. URS Company, Draft Environmental Impact Statement, Crude Oil Transport
Alternates From Naval Petroleum Reserve No. I Tupman, California, Part Two Elk
Hills/Port Hueneme Conveyance System, for the Department of the Navy, Naval
Petroleum and Oil Shale Reserves, Washington D.C., 18 April 1977, Sec. 1, p. 25.

22. California State Lands Commission, California and the Disposition of
Alaskan Oil and Gas A Working Paper, June 1976, Ch. VI, pp. 5-11.

575

CHAPTER 21

'DEVELOPMENT SCENARIOS:
WORKS IN'PROGRESS

As a guide to the potential range of effects and of possible onshore facili-
ties, this chapter describes the timing and extent of OCS-related development on
existing leases and in areas that may be leased as a-result of Proposed Lease Sale
#48. The choices for OCS development appear here as scenarios describing
activities that could take place, from the point of.lease sale through exploration,
development, production, processing, and transportation of crude oil and natural gas.
The scenarios present choices for OCS development because continued OCS development
off southern California is inevitable: two platforms have been installed within
the last year; two development plans are currently being prepared; as many as eight
exploratory vessels have been working.at one time; over one billi6n dollars has
been spent to acquire the offshore leases; and, over 200 million dollars has been
spent exploring and developing these leases. The possibility of buying back these
leases is remote at best: four times under the Nixon Administration attempts were
made in Congress to buy back certain leases in the Santa Barbara Channel and each
time they failed. It would be naive to believe that future OCS development on,
existing leased tracts can be prevented, but it is equally naive to believe that
such development will automatically meet local and State concerns for environmental
protection expressed in this and numerous other documents. These scenarios, there-
fore, are seen as a way of integrating many otherwise separate projects in order
to avoid unnecessary environmental risks.

Use of scenarios which anticipate potential conflicts in the process of
estimating the scope of future development permits OCS proposals to be evaluated
from a broad perspective; individual projects.need not be considered as if each
were an isolated event. Thus, the scenarios presented here are to be seen as
illustrative, depicting a set of reasonable options for future OCS development that
fit within a broader framework of feasible offshore and onshore opportunities.
When these choices are considered as a whole, transportation and processing
options emerge as the major opportunities for lessening environmental -impacts
and for reducing costs -- both the production costs of industry and the infra-
structural costs of the coastal communities involved.

These descriptive scenarios are, however, necessarily limited by the amount
of available information and by the unpredictability of numerous variables affect-
ing OCS activities -- for example, the supply of exploratory vessels; the availabil-
ity of production platforms; delays caused by moratorium, governmental regulation,
or litigation; corporate decisionmaking on capital expenditures in a given area;

577

the need to balance regional energy supply and demand; etc. A hypothetical
scenario demonstrating the sequence of exploration and development and the
inherent difficulties in predicting this'sequence with precision is described
in the passage below, quoting a letter to the Office of Pl'anning and Research
from an industry representative. The field unit under discussion in the letter
encompasses more than one prospect and drew considerable interest at the time
of the Channel lease sale. The industry spokesman writes:
Let us assume than an evidently commercial discovery is made
at or above the 9,000-foot required depth. Our next obliga-
tion would be as soon as possible to file for the approval of
the USGS a second exploratory plan of operation as provided
in Sec. 10.1 of the Unit Agreement. This plan could conceiv-
ably require the drilling of two to four or five wells to
delineate the producing structure and to assure ourselves of
the number and type of platforms required and amount of capital
necessary. Following the delineation of the field which would,
if the wells were successful, obviously be an accelerated
drilling program using one or perhaps more than one drilling
vessel, we would submit a plan of operation for the development
of this proven sector of the unit. The plan of development
would be a rather comprehensive one calling for the construction
and emplacement of a platform or platforms. It is to be hoped
that by that time the environmental impact procedure would be
somewhat narrowed from what it is today, so that instead of
opening the subject to consideration of matters that already
have been largely resolved in the Santa Barbara Channel area,
these hearings would involve only the alternatives of handling
production and processing of the oil and the associated impacts
to be borne by the outlying communities as the result of such
a volume of additional oil. After the conclusion of the NEPA
procedure, a contract for the construction of platforms would
be let for the reason that the size and sophistication of such
platforms would not be known at any earlier time. After plat-
forms had then been constructed and placed on location, then
only would development drilling begin.

Under any circumstances, it does not appear that production
could be initiated in less than four (4) years from the date of
discovery, and it is realized that in making this estimate
there would have to be some emergency or urgency for the resolu-
tion of the many questions involved in such a short time. A
more realistic estimate would, no doubt, be five (5) years after
the date of discovery that production could begin. Again, after
production commences, it would take an appreciable time before
say 50 or 60 wells could be completed if the oil-bearing struc-
ture indeed proved to be that large. The production curve would
probably peak at or about the time the field became fully
.developed. I/

Recognizing the limits to and the inherent difficulties in predicting the
timing and extent of future OCS-related development, this chapter adopts a
conservative view towards the changes that could take place. That is, speculation
for areas having proven recoverable reserves is presented with considerably more
specificity than for those areas of relatively unknown potential. Rates of pro-
duction (assuming reasonable time sequences for development) have been projected

578

only for those discoveries having estimates for recoverable reserves. 'Other
discoveries are described in terms of possible range of production.
The scenarios are generally presented in a descending order of,degree of
reliability, those with most information available appearing first. They-are also
grouped into four categories: those for fields already in production; those for
leases wi-th discoveries but not yet in production; those for leases without
discoveries; and, unleased areas that may be offered.in Lease Sale #48.. The fields
or areas reviewed-are as-follows:

Fields in production
1. Carpinteria Offshore
2. Dos Cuadras

Leased areas with discoveries (but no production,)
3. Santa Ynez Unit
4. Hueneme Offshore
5. Santa Clara Unit
6. Pitas Point Unit
7. San Pedro.Bay

Leased-areas without discoveries
8. Oak Ridge Unit
9. San Miguel Unit
10. Santa Cruz Leases
11. Outer Banks

Unleased areas.that may be offered in Lease Sale #48
12. Santa Barbara Channel.
13. San Pedro Bay
14. San Diego Coast
15. Outer-Banks

The summary below predicts OCS development for the next several decades.
Most readers concerned with southern California OCS development in general should
find this summary adequate for their purposes, while the scenario secti.on.that
follows the Summary is provided primarily for corroborative detail and for
decisionmakers who must ultimately piece together the many separate developments
into a logical whole * To those who would read the scenarios in their entirety,
we caution with the words.of our editor who wrote after reviewing an earlier,draft:
"I accept that this extended analysis-is bas.ic to the report, a necessary pro forma
exercise. But it must also be accepted that-few, i.f any, will read.through what is
inevitably a tedious recital, Byzantine in complexity and redundant in concept." 21.

In addition to the summary below, all of the development choices --;- and the
recommendations of this report regarding those choices -- are capsulized in Chapter
11. Appendix 2 of this report provides a detailed explanation of how production:
rates and estimates of recoverable oil and gas were derived. Finally, A.ppendix 3
provides.extensive information on each of the existing facilities in-the scenari,os..

38--76658 579

SUMMARY

Provided on the following-pages are several figures that graphically illus-
trate the principal findings and conclusions of the scenario studies.

Figure 1 shows all existing leases off southern California, with estimates of
economically recoverable resources for each leased area. To qualify these estimates
properly, the reader is referred to Chapter 14 wherein sources, methods of
derivation, and reliability of the numbers are discussed. Here, we must stress
that these estimates are, for the most part, of undiscovered resources (with the
partial exception of the Santa Barbara Channel) and should t be taken literally
as oil and gas waiting for the right moment to come ashore. Rather, these re-
sources must still be discovered within the geographic areas suspected of contain-
ing them. Once discovered, they must be further explored, delineated, and tested

found to be economical must pass the tests of regulatory authorities concerned
to determine if they can be economically recovered. Finally, those discoveries

with the safety of offshore operations before these resources can be produced.
The importance of Figure 1 is to provide-a sense for the volumes of potentially re-
coverable resources in each leased area.

In Figure 2 we show routes for pipelines that combine the best fit between
least distance, shallowest water, and available onshore facilities for transport-
ing crude oil and natural gas to shore. Chapter 20 discusses OCS pipeline routing
criteria and state-of-the-art laying capability that were influential in defining
these routes. Although these pipelines would follow the shallowest paths possible,
they cannot avoid water depths in some areas that exceed current state-of-the-art
capability. However, based on significant developments in the last several years,
we conclude that pipelaying capability for the routes shown in Figure 2 can be
achieved in the next five years -- the same time required to discover, explore, and,
if feasible, develop the undiscovered resources offshore.

Since the Santa Barbara Channel is likely to be most heavily developed in the
near future, Figure 3 shows clearly the pipeline route that will be required if
that area is to reduce air pollution and the risks of oil spills associated with
tankering. These pipeline routes again combine the same criteria mentioned above.
They also conform more closely to the location of existing discoveries, with the
exceptions of the San Miguel, Oak Ridge, and Santa Cruz areas where no discoveries
have been made yet. The offshore pipeline routes for the east end of the Channel
are not restricted by water depths and could be laid today if the various dis-
coveries are found to be economical. The route linking Hueneme and Santa Clara
is now being evaluated by the operators of those two areas.
For the west end of the Channel, beyond Hondo, water depths reach a maximum
depth of around 1500' between the San Miguel and Pescado areas. A shallower route
to shore from the San Miguel area would be possible if a pipeline were laid to the
eastern end of the Channel, but the distance travelled would be triple that re-
quired for the route shown.
Figure 4 shows the location of existing, proposed, and possible OCS-related
facilities in the Santa Barbara Channel. This display is useful for identifying

580

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Barbara interia Figure
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RECOMMENDED PIPELINE ROUTES:
SANTA BARBARA CHANNEL
C
I @147 S@ACA7

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Recommended Offshore Pipeline Route o Proposed Exxon Processing Plant 10
4NORTH SCALE
Recommended Onshore Pipeline Route 9 Existing Production Site April 1977 Ca
Existing Dos Cuadras Pipeline 0 Possible Production. Site

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OCS -RELATED FACILITIES:
SANTA BARBARA CHANNEL

In Leased Area
n Existing Platform
o Proposed or Possible Platform 10 1
9 Existing Processing Plant 10
o Proposed or Possible Processing Plant NORTH SCALE
A, Existing Marine Terminal April 1977 C
A Proposed or Possible Marine Terminal

at a glance those areas most likely to be affected by offshore oil and gas devel-
opment in the near future. Note, however, that some "proposed or possible" facil-
ities represent alternatives: not all of these will be constructed. Similarly,
not all possibilities can be anticipated: platforms for the Pitas'Point Unit, Oak
Ridge Unit, San Miguel Unit, the Santa Cruz leases, and the Anacapa leases are not
illustrated because information about these areas is insufficient for projecting
possible development. Finally, not all facilities shown are involved in the
scenarios@: State tideland platforms and related facilities are not discussed;
they are shown primarily for reference. Below, we list all facilities by name
and cross reference those that are discussed in the scenarios. Additiona.1
information on each of the existing facilities is provided in Appendix.3 of
this report.

PLATFORMS
Pl: Herman (existing, State tidelands
P2:- Helen (existing, State tidelands@
P3: "Sacate" (possible, see Santa Ynez Unit scenario)
P4: "Pescado" (possible, see Santa Ynez Unit scenario)
P5: "Hondo V (possible, see Santa Ynez Unit scenario)
P6: "Hondo B" (possible, see Santa Ynez Unit scenario)
P7: Hondo A (existing, tee Santa Ynez Unit scenario)
P8: Holly (existing, State ti-delands)
P9: Dos Cuadras C (existing, see.Dos Cuadras scenario)
PIO: Dos Cuadras B existing-1 see.Dos Cuadras scenario)
Pll: Dos Cuadras A @existing, see Dos Cuadras,scenario)
P12: Hillhouse (existing, see Dos Cuadras scenario)
P13: Hilda (existing, State tidelands)
P14: Hazel (existing, State-tidelands)
P15: "Henry" (proposed,,see Carpinteria scenario)
P16: Houchin (existing, see Carpinteria scenario)
P17: Hogan (existing, see Carpinteria scenario)
P18: Hope (exi'sting, see Carpinteria scenario)
P19: Heidi (existing, see Carpinteria scenario).
P20-: Rincon Island (existing, State tidelands)
P21: "Santa Clara A" (proposed, see Santa Clara Unit scenario
P22: "Santa Clara B possible, see Santa.Clara Unit scenario
P23: "Santa Clara C @possible, see Santa Clara.Unit.scenario@
P24: "Hueneme" (proposed, see Hueneme scenario)

MARINE TERMINALS
Ml: Union CoJq Bay (existing, tidelands-related).
M2: Getty/Gaviota (existing, tidelands-related)
M3: Exxon/OS&T (alternative, see.Santa Ynez Unit scenario)
M4: "Exxon/El Capitan" proposed:, see Santa Ynez Unit scenario
M5: Exxon/El Capitan Zisting, see Santa Ynez Unit scenario
M6: "Aminoil/Naples" (proposed, see Santa.Ynez Unit scenario)
M7: Aminoil/Elwood (existing, see Santa Ynez Unit scenario).
M8: Chevron/Carp.interia (exis.ting, see Santa Clara Unit scenario)
M9: Getty/Ventura. (existing,,see Dos Cuadras scenario)
M10: Union/Ventura. (existing,.see Dos Cuadras.scenario)
Mll: "Chevron/OS&T" (possible, see Santa-C-lara,Unit scenario)
M12: "Mobil/OS&T" (possible, see@Hueneme scenario)'

585

PROCESSING PLANTS (Treatment and Storage Facilities)
T1: Union7Pt- Conception (existing, tidelands-related)
T2: Texaco/Gaviota (existing, tidelands-related)
T3: Chevron/Gaviota (existing, tidelands-related)
T4: Arco/Gaviota (existing, tidelands-related
T5: Phillips/Tajiguas (existing, tidelands-related@
T6: Shell/Molino (existing, tidelands-related)
T7: "Exxon/OS&T" (alternative, see Santa Ynez Unit scenario)
T8: "Exxon/Las Flores" (proposed, see Santa Ynez Unit scenario)
T9: Shell/Corral Canyon (existing, see Santa Ynez Unit scenario)
TIO: Arco/Elwood (proposed, tidelands-related)
Tll: Aminoil/Elwood (existing, tidelands-related)
f12: Arco/Coal Oil Point (existing, tidelands-related)
T13: Chevron/Carpinteria (existing, see Santa Clara Unit scenario)
T14: Rincon Island (existing, tidelands-related)
T15: Phillips/La Conchita (existing, see Carpinteria scenario)
T16: Mobil/Rincon (existing, see Dos Cuadras scenario)
T17: Mobil/Sea Cliff (existing, tidelands-related)
T18: Cabot/Sea Cliff (existing, tidelands-related)
T19: Chansler-Western/Sea Cliff existing, tidelands-related)
T20: Chevron/OS&T @possible, see Santa Clara Unit scenario)
T21: "Outer Banks/Ventura" (possible, see Outer Banks scenario)
T22: "Mobil/Mandalay: (possible, see Hueneme scenario)
"Mobil/OS&T" (possible, see Hueneme scenario)

Figure 5 shows the timing and sequence of exploration, development, and
production projected for the scenarios,' includi6g the installation of individual
platforms where information is available. What should be immediately apparent from
this graph is the widely divergent schedules,under which different areas of the OCS
have been developed. Similarly, it should be clear that the greatest amount of OCS
development is yet to occur.

Figure 6 returns to the Santa Barbara Channel again to illustrate the potential
rates,of produ.ction based on existing development plans only. The significance of
the Santa Ynez Unit to Channelwide planning for increased levels of OCS development
is conspicuous. Yet, as is discussed in the scenario, a great deal of uncertainty
remains regarding the total magnitude of the Santa Ynez-Unit contribution to future
production. The graph clearly shows-the differences that result from assuming dif-
ferent numbers for total recoverable reserves: 419 MMB being derived from Exxon-
supplied information, 730 MMB and 1,100 MMB being a range of recoverable crude oil
estimated by the Geological Survey.

THE SCENARIOS

F I E L D S I N P R 0 D U C T 1 0 N

Production in the federal OCS is presently limited to two fields: Carpinteria
and -Dos Cuadras, located along the same geologic formation known as the Rincon
trend, off the coast of Santa Barbara County. Figure 10 of Chapter 19 shows the lo-
cation of these two fields together with production facilities, those already in
place, and those proposed for development.

586

FIGURE 5:
TIMING AND.SEQUENCE OF SOUTHERN CALIFORNIA OCS DEVELOPMENT

OUTER-BANKS

SANTA CRUZ +

SAN.MIGUEL +

OAK RIDGE +000

SAN PEDRO BAY
(SHELL ONLY) +

PITAS POINT +00 U3 On

SANTA CLARA + 6XAC Z7

HUENEME now

1%"TF @Now

ONE a
SANTA YNEZ +13 U OMU13UU

MEN
DOS CUADRAS +C]

OCS-P 0240 +0013 0
4AUCw1,V
OCS-P 0166 v4vAl
CARPINTERIA +1313

1965 1970 1975 1980 1985 1990 1995 2000 2005

+ Lease Sale

or3a Exploration and Development P1anning,

.one Field Development

Production

587

FIGURE 6:
SANTA BARBARA CHANNEL FEDERAL OCS CRUDE OIL PRODUCTION FORECAST

340

330 - -
320 - - 00 mm

310 - -

300

290 - -

280 - -

270 - -

260 - -
250 lo,
240 - -

230 - -

220 - -

210 - -

200 -

190 - -

180 - -
Ln
00 170 - -
00 160 - - 730 MMB'11%
150

140 - -
130 - - lo,
120 - -

110 - -
SANTA,YNEZ
100
419 MMB"ll
90 - -

80 - -

70 - -
V,
60 - -

50 - -
<
40 - - HUENEME
C) 30 - - DOS CUADRAS SANTA CLARA

20 - -

10 - -
0 CARPINTERIAl I
0
1968 69 70 71 72 73 74 75 76 77 78 79 RO RI R2 R.3 R4 85 R6 R7 8R R9 90 97 92 93 94 95 96 97 98 99 2000
TIME
@@@HU@ENEME
DOS CUADRAS @SANTA C@LARA
I
ICARPINTER ALI

CARPINTERIA

Operators: Phillips, Sun
Prospect: Carpinteria
Exploration: Phillips completed; Sun currently evalu-
ating 1976 -well
Development: Phillips completed; Sun evaluating
Production: Phillips started in 1968; Sun earliest
projected for 1979
Production Systems: Phillips' Houchin and Hogan, 1968; Sun
proposed "Henry"
Processing: Phillips/La Conchita for P'hillips; Sun
proposes processing at their Platform
Hillhouse on Dos Cuadras field, then to
Mobil/Rincon
Transportation: onshore pipeline and tanker options avail-
able to both.

The Carpinteria field straddles the boundary line between state and federal
waters. Initial production from the field occurred in.state waters from Platforms
Hope and Heidi on a State tidelands lease granted to Standard Oil of California
and Arco in 1966. When structural analysis of geologic conditions indicated that
this field extended into federal waters, the Department of the Interior authorized
a drainage sale of adjacent federal OCS submerged lands. A consortium of Phillips
Petroleum, Continental Oil, and Cities Service were high bidders on December 15,
1966, for the acreage offered as Lease OCS-P-0166. Phillips became the designated
operator of 0166 for development phases. In 1960, a major lease sale was held in
the Santa Barbara Channel. Adjoining submerged lands to 0166 were leased as OCS-
P-0240 to a consortium made up of Sun Oil Company, Marathon Oil Company, Sunray DX,
and the Superior Oil Company. Exploration on 0240 in 1969 confirmed an extension
of the Carpinteria offshore field into it.

EXPLORATION. Exploration on 0166 was completed with six core holes drilled in
1967. By 1968,7development plans for the lease were completed and two platforms
were installed. Subsequent exploration by Sun, the adjoining tract operator, con-
firmed an extension of the Carpinteria field into OCS-P-0240. It is yet unknown
whether oil and gas from this extension is economically recoverable.

DEVELOPMENT. The Carpinteria field is developed with two production platforms
in state waters and two in federal waters. No apparent effort was made during field
development to accommodate field unitization, either by the companies involved or
by state and federal regulatory agencies. It is unclear whether or not unitization
would have actually increased ultimate recoverable reserves; however, it can be demon-
strated that unitization would have eliminated the cost of some pipelines to shore
and possibly the Phillips processing facility. @/

PRODUCTION., The federal portion of the Carpinteria field began to produce in
-June 1968 and peaked in August 1969 at 27,899 barrels of oil per day. It current-
ly produces about 4,500 barrels of oil, 2,280 MCF of gas and about 9,000 barrels of
water per day. The peak number of producing wells for the two platforms was sixty
in February 1970; the curreni number of producing wells is forty-eight. 4/ The re-
maining productive life of the two platforms is estimated to be eight to ten years.

TRANSPORTATION. Production from the Phillips pl atforms goes to shore for

589

treatment and separation by way of two ten-inch diameter pipelines for oil and
one twelve-inch diameter pipeline for gas, each approximately 6.15 miles long.
Phillips operates the pipelines and pumping equipment, designed to handle around
42,000 barrels of fluid (15,000 water and 27,000 oil) and 22,500 MCF of gas per
day. After processing, surplus gas is sold to the Pacific Lighting Company which
operates a pipeline adjacent to the onshore facility, while oil is transferred to
a 55,000 barrel storage tank operated by a Phillips pipeline company. This pipe-
line company connects with the Ventura Pipeline Company (described in the
scenario for Dos Cuadras production) to transport the oil through a 30-inch pipe-
line to the Ventura area, where additional pipelines and two marine terminals link
with refining areas.

PROCESSING. Federal Carpinteria production is processed at the Phillips-La
Conchita treatment and separation plant, located at the foot of coastal bluffs
along Ventura County's Rincon coastline some 1.5 miles west of Rincon Point. The
site covers approximately 16 acres, 11 of which are occupied. The remaining four
vacant acres were proposed for development by Sun Oil in 1969. 6/

The Phillips-La Conchita Drocessing plant was originally designed to treat
around 27,000 barrels of oil, )5,000 barrels of water and 22,500 MCF of gas per
day. Current design has reduced gas handling capability to 11,000 MCF/D and
wastewater disposal to around 9,000 B/D. The original design for disposing of
treated wastewater relied on an ocean outfall. Since present regulations prohibit
this method of disposal, Phillips converted a six-inch freshwater line, formerly
connecting the platforms with an onshore water system, into a wastewater return
line. At the platform, the wastewater is disposed of by injecting it into already-
depleted areas of the Carpinteria field.

Current production is at 4,500 B/D oil, 9,000 barrels of water and
2,280 MCF of gas per day. These production levels allow a surplus treating,capa-
city estimated at 22,500 B/D oil and 8,800 MCF of gas per day. Phillip's
personnel indicate that to process any new oil and gas including significant
quantities of water would require new wastewater disposal pipelines. 7/

FUTURE DEVELOPMENT FOR THE CARPINTERIA FIELD. Sun completed four exploratory
,wells in the vicinity of the-Carpinteria extension by 1970, when it submitted a
development plan to USGS. That plan requested permission to drill up to three
additional exploratory wells and to install Platform Henry approximately 1-1, miles
west of Platform Houchin, should the results favor further development. This
request, along with an application to install Platform C on the Dos Cuadras field
(see a discussion of this proposal in the Dos Cuadras scenario), was the subject
of a federal Environmental Impact Statement in 1973. The Secretary of
Interior denied approval of both platforms on environmental grounds in that year.
Following the decision, both applicants initiated lawsuits against the Department
of the Interior. In September 1976, Union vs. Morton [(1975) 512 F.2d 743] was
settled in' favor of Union, with the stipulation that USGS quickly provide all nec-
essary permits for installing Platform C. Further, as a factor in settling Santa
Barbara County, et al - vs. Kleppe (Civil Action No. 76-0245-MML), the County agreed
not to seek further legal action that would impede or delay the development plans
for Platforms C and Henry. Sun's suit against Interior is still pending before the
United States Court of Claims. Proposed findings of fact and conclusions of law
have been filed with the court, but no hearing date has been set. 8/

With approval of Platform C as a precedent, it appears likely that the
development plan for Henry will also be approved. USGS has estimated probable

590

reserves of 12.75 MMB oil and 8.66 BCF gas to be recoverable by Henry. 9/ We
assume that Sun installs Platform Henry on 0240 in 1978, that production begins
in 1979, peaks in 1980 at 8,000 B/D oil and 4,000 MCF/D gas, and declines there-
after. The peak oil rate and t -he gas/oil ratio (GOR) are extrapolated from the
production history of tract 0166. Productive life of the new platform is ' assumed
to be 15 years. Production life for Houchin and Hogan is estimated to last until
1986 by Phillips; but, if Henry is installed and required to use Phillips facilities,
it would be fair to assume Houchin and Hogan would stay in operation past their
anticipated economic life.

TIMING FOR FUTURE ACTIVITIES ON THE CARPINTERIA FIELD. If approval of the
development plan for the exploratory wells and Platform Henry is obtained by the
end of ,1977, exploration may begin by mid-1978 and conclude in early 1979. A
commitment for Platform Henry to be installed would be made i-n late 1978 and begin
in mid-1979. Under these assumptions, development drilling and initial production
could occur in 1980.

Transportation and processing options include linking by way of a half-mile
pipeline with Phillip's Platform Houchin to bring oil and gas ashore at Phillips-
La Conchita; or linking by way of a two-mile pipeline with Sun's Platform Hillhouse
on the,Dos Cuadras field to bring oil and gas ashore at Mobil-Rincon. Sun prefers
the latter option forseveral reasons. First, Platform Hillhouse is designed to
separate completely crude oil, water, and natural gas to "pipeline quality" stan-
dards. By directing its Carpinteria production to Hillhouse,'Sun would save the
expense of purchasing processing capability from.Phillips at La Conchita. Second,
Sun.1s part owner and is entitled to a portion of the available surplus capacity
in both the pipelines from Dos Cuadras to Mobil-Rincon and in the Mobil-Rincon
facility itself. Sun's share of surplus capacity exceeds the projected peak rates
of production for Platform Henry and'hence would permit use-of these facilities
without additional costs above the current th 'roughput rate charged for operating
them. Third, and most important to Sun, the preferred option simply avoids the
complicated process of setting up joint-use agreements with another company, in
this case, Phillips.

The Phillips option has two advantages: it reduces the length of pipeline
required to deliver crude oil and natural gas to a processing site; and it reserves
surplus capacity at Mobil-Rincon for other future production. A disadvantage
of the Phillips option would be the extended life required of Phillips-La Conchita.
Production from Henry could sustain operationof the plant to the year 1993, or
seven years past its current life expectancy, thus delaying the recycling of this
site to other coastal-related uses.

DOS CUADRAS

Operators: Union, Sun
Prospect: Dos Cuadras
Exploration: Complete
Development: Complete, with possible addition of
satellite, ocean-floor wells
Production: Begun 1969
Production Systems: Union Platforms A, B, C; Platform Hillhouse
Processing: Mobil/Rincon
Transportation: Onshore pipeline to Ventura, pipeline and
tanker options from Ventura to refineries

The Dos Cuadras field was discovered in Lease OCS-P-0241 in 1968 by the

591

leaseholders -- Gulf, Texaco, Union, and Mobil (GTUM), with Union as tract opera-
tor. Further exploration in 1968 by Sun demonstrated an extension of this field
into OCS-P4240, held by Sun, Marathon, and Superior, with Sun as operator.
Exploration activities ceased in late 1968 when platform installation began.

DEVELOPMENT. The development plans for the field require three platforms for
the GTUM portion and one platform for the Sun portion. Union installed Platforms
A and B by February of 1969 with intent to install Platform C in March of that
year. Sun's plans called for installing Platform Hillhouse in late 1969. Platforms
A, B, C, and Hillhouse are currently in place and producing, although permission to
install Platform C was delayed until recently (described below). No further devel-
opment for the Dos Cuadras field is contemplated beyond the possible addition of a
few satellite, ocean-floor wells.

PRODUCTION. Production for the Dos Cuadras field-began at the time of the
1969 blowout, peaked in 1971 at 81,000 B/D oil from A, B, and Hillhouse, and cur-
rently amounts to about 34,500 B/D oil and 11,300 MCF/D gas. The peak number of
producing wells was 129 in 1973 and is currently 122. 10/

TRANSPORTATION Transportation of production to shore for treatment and
separation is facilitated by commingling production at Platform A, then pumping to
shore through two 12-inch pipelines approxi,mately 11 miles long. The pipelines and
related pumps, operated by Union, Oil, are designed to handle approximately 96,000
B/D oil and 60,000 MCF/D gas. Once ashore, production is pumped to the Mobil-Rincon
processing site at an elevation of approximately 500' through a 20-inch oil pipe-
line and a 20-inch gas pipeline. After processing, gas enters a Pacific Lighting
Company gas line on-site; and custody of oil automatically transfers to the Ventura
Pipeline Company. ll/

The Ventura Pipeline Company-was formed to own and operate a pipeline connect-
ing the Phillips-La Conchita processing plant on the north to a 268,000-barrel
storage tank at Mobil-Rincon and a pipeline continuing south to the City of
Ventura. The Ventura Pipeline Company also owns the storage tank at Mobil-Rincon.
The company consists of the GTUM group, the Sun group, the owners of Phillips-La
Conchita (Phillips Petroleum, Cities Service Oil Co., Continental Oil Co.), Arco,
and Chanslor Western. It is operated by the Mobil West Coast Pipeline Company, a
subsidiary of Mobil Corporation.

In Ventura, the pipeline diverts oil to any of two marine terminals and three
pipelines capable of delivering production to refining areas. 12/ Two of the
pipelines from Ventura to Los Angeles are owned by GTUM members (Texaco and Union).
One marine terminal is also owned and operated by Union Oil. This terminal,Union/
Ventura, is capable of loading crude.oil at a rate of 10,000 barrels per hour
through a 20-inch line and 6,400 barrels per hour through a 10-inch line. The
20-inch line is used about 33 times per year, lifting 200,000 barrels per tanker
visit. It is not clear how much of Dos Cua.dras production uses this particular
marine terminal; however, a typical month's loading of 645,000 barrels total (3 X
200,000 + 45,000) is significantly less than the one million barrels per month
currently being produced.

PROCESSING. Processing of Dos Cuadras production takes place at Mobil/Rincon,
a treatment and separation plant owned jointly by GTUM (with four equal shares at
17PA) and the Sun group (with shares totaling 30%). 13/ This site is located on a
terrace along the coastal bluffs of Ventura County, approximately 3.4 miles south-
east of the Ventura County-Santa Barbara County line at Rincon Point, and 1.2 miles

592

due south of Rincon Mountain. Of the 140 acres, 20 on the north are reserved as
a-buffer zone. The processing plant and a 268,000-barrel storage tank owned by
@the-Ventura Pipeline Company occupy about 32 acres. An estimated five of the 32
acres are available for expansion with no grade preparation necessary. An addi-
tional ten acres adjacent to the processing plant could be used, with minimal grade
modifications. The remaining 78 acres are in a relatively natural state of rolling
grass and brus-h-covered terrain, including,some very steep bluffs.

The processin g facility is designed to handle 96,000 B/D oil, 60,000 MCF/D
gas, and 50,000 barrels of wastewater per day. Inadequate pipelines, however,
limit the disposal ofwastewater to 14,000 barrels of water daily. Accomodation
of new.production without increasing wastewater disposal will necessitate disposing
of nearly all produced water at the producing site. 14/

FUTURE DEVELOPMENT FOR THE DOS CUADRAS FIELD. Union Oil applied for and received
approval for Platform C in September 1968, anticipating installation in March
1969. When the Platform A blowout occurred in February 1969, installation was
del-ayed. In April 1969,,the Secretary of the Interior Withdrew the earlier appro-
val. Subsequent reapplication, EIS review, and legal action resulted in further
delays for Platform C. The Secretary finally approved Platform C on June 14, 1976,
contingent on the U.S. District Court approval of the settlement of the suit
between Union and others against the Secretary. On A,ugust 31, 1976, the District
Court entered an order of judgment approving the settlement. 15/ Platform C was
subsequently installed in February 1977.

TIMING OF FUTURE ACTIVITIES ON THE D05 CUADRAS FIELD. The Court decision
affecting Platform C requires USGS to provide Union Oil with all necessary permits
to install and commence production without further delay. Therefore, we project
new production from Platform C to begin in 1977, peak in 1979 at 6,900 B/D oil and
2,400 MCF/D gas, and decline thereafter. 16/ The peak oil rate is speculative;
the GOR is extrapolated from Dos Cuadras production history; and productive lifetime
of the new platform is assumed to be 15 years.

Platform C production will require a new pipeline segment, approximately 1.5
miles in length, linking it with Platform A, thereby allowing new production to
flow through the existing 12-inch pipel.ines to the Mobil-Rincon processing plant.
No alternatives for Platform C production are proposed since the project as des-
cribed has been essentially approved.

L E A S E D A R E A S W I T H D I S C 0 V E R I E S
(B_U T N 0 P R 0 D U C T 1 0 N)

In addition to the two currently productive fields described above, eight
additional fields in the federal OCS have been discovered and are in various
stages of exploration or development. The.eight fields and their initial discovery
dates are the following: Pitas Point Offshore, 6/19/68; Hueneme Offshore, 6/19/69;
Hondo Offshore, 7/13/69; Pescado Offshore, 5/2/70; Sacate Offshore, 8/30/70; the
Santa Clara south field,,,11/22/70, and north field, 3/4/71; and the unnamed San
Pedro Bay field, July 1976. 17/ All of these are in the Santa Barbara Channel
except the San Pedro Bay discovery. The five- to seven-year interval between field
discovery and development is not typical of field development but rather is a
result of federal moratoriums in effect between 1969 and 1975.

Of the eight fields, three occur in the Santa Ynez Unit, one in the Hueneme

593

Offshore area, two in.the Santa Clara Unit, one in the Pitas Point Unit, and one
in San Pedro Bay.

SANTA YNE2 UNIT

Operator: Exxon
Prospects: Hondo, Pescado, Sacate, P-0197
Exploration: Complete for Hondo, more proposed for
remainder of unit
Development: Hondo plan filed 1973, initial platform.
in place, two additional systems contem-
plated for Hondo, one system each.
contemplated for.Sacate and Pescado (total
of five for unit)
Production: Mid-1978
Production Systems: Hondo Platform A in 850' water, Hondo B
and C, Sacate, and Pescado.require deep-
water technology (ocean-f-loor or compliant
tower systems)
Processing: Exxon/Las Flores Canyon proposed alternate.
offshore storage and terminal (OS&T) now
under construction
Transportation: Tankers proposed

The Santa Ynez Unit is estimated to contain more oil and gas than any-other
discovery in the Channel. 18/ It presently consists of 17 leases acquiredAn the
1968 Santa Barbara Channel lease sale. Exxon, the designated operator, controls
92% of the worki-ng interest in,the unit, with the remaining interest he-ld by,
Standard Oil of California and Shell. The unit is currently credited with the
Hondo,, Sacate, and Pescado field discoveries. In 1969, USGS.also showed a discov-
ery in lease 0197 on an official Santa Barbara-Channel OCS map. j9/ Subsequent.
revisions to,this map in 1973, 1974,,and 1975 omitted this dtsc@overy; however, in
1976 Exxon produced a map that again showed.this phantom field in lease 0197.. 20/

EXPLORATION. Exploration of the unit began in 1968, and 32 exploratory wells
have been completed to date. Exploration of the Hondo prospect has led Exxon to
submit a development plan for that portion of the unit; however, Exxon estimates.
that four to six additional wells will be needed on the Sacate and Pescado pros-
pects before development commitments can be made. 211

DEVELOPMENT. Exxon's-plan for the Hondo prospect calls for constructing a
28-well platform in 850 feet of1water on the east end of the field. This plat-
form will be augmented later by-two additional facilities to develop the western
3,300 acres of the prospect. Quoting,from Exxon:

These facilities will'be a fixed platform, located in 900-
1,000 feet of water to develop the northern flank of the
structure, plus a Submerged Production System located in up
to 1,500 feet of water to develop the southern structura-1
flank. A Submerged Production System may,be used in place
of the 900 to 1,000 foot platform, making the.total Hondo-
Field development the 850 foot-platform and two Submerged
Production Systems. Production from Submerged.Production
Systems would be pipelined to the initial 850 foot platfom.:22/

The initial Hondo platform was installed in December 1976@ The first wells

594

are to be drilled in late 1977 with production from-the platform expected in
April 1978. Installation of the additiona.1 production systems is projecied for
1982. Exxon expects that complete development of the Hondo prospect (with-the
two additional production systems) will result in a peak flow of 60,000 B/D oil
and 90,000 MCF/D of sales gas, with ultimate recovery of 240-250 MMB of oil and
360 to-375 BCF of sales gas. 23/-

Development of the Sacate and Pescado fields depends on further exploration
and flow tests on the Hondo.prospect. Exxon representati,ves have indicated that
no decision to develop Sacate and.Pescado will be made before 1979. Exxon states
that, "Although additional drilling will be necessary prior to finalizing develop-
ment plans, a fixed platform in 1,000 to 1,290 feet of-water or a Submerged Produc-
tion System in conjunction with a surface.support structure will be.given
consideration" for the Pescado area; another platform is'probable for the Sacate
area@ 24/ Allowing three years for the. design., fabrication, and assembly of the
required production facilities, and about one year.for development.drilling and
pipelaying to connect these-production systems with processing.facilities, produc-
tion could probably begin in 1983.: Designspecifications of the proposed Las
Flores Canyon processing plant are for a peak flow of 80,000 B/D'oil, with GOR
close'to 1,100. 25/ -Under these circumsta.nces, ultimate recovery would be around
419 MMB of oil, assuming a typical OCS field performance and a Droductive
lifetime for the unit of 30 years.

TRANSPORTATION.. Transportation of Santa Ynez Unit production is one-:of the
most'controversiaFissue� currently facing pub1ic agencies concerned@with OCS.
development. Exxon.proposed-to transport all production.to shore for treatment
and separation of liquids and gas-, sell.the gas to.a.natural-gas company,at the
edge-of the onshore sitei and transport.the processed crude to-refineries via a
new marine terminal. This facility would be des.igned to store up to 440,000
barrels of oil. Assuming peak.production of 80,000 B/D, a.mihimum of one tanker,
visit every five days would be required.

A permit granted by the California Coastal Commission for the onshore.pro-
cessing plant and the marine.terminal, imposed a condition that the marine
terminal be used:on an interim basis.to transport the crude oil pending the
outcome of a feasibility study for a pipeline.to refineries in the Los Angeles
Basin or other suitable destination. Exxon chose not to accept this condition
and is currently constructing a floating off's.hore storage-and.terminal (OS&T)
facility in federal waters capable of.separating fluids and gas,'but not capable
of treating the produced gas or transporting.it to a gas company. As a consequence,
the natural gas would be reinjected into the Hondo reservoir. The OS&T could treat
up to 60,000 B/D@oil and store up to 200,000 barrels. This production rate would.
necess.itate at least one tanker visit every -three days durinq peak i)roduction..

Muc h of the controversy over the transportation of Santa Ynez Unit production.
focuses on the economic feasibility of the pipeline,-a factor directly dependent-
on pipeline.throughput...' It is therefore apparent that production forecasts are
a critical.determinant-to transportation options for Santa Ynez Unit crude oil,.%
It is equally,apparent, after reviewing-published reserve estimates., that produc--
tion scenarios derived from information provided by Exxon may be overly.
conservative.

Earlier production scenarios for the unit.have:accepted certain parameters
Exxon and the Department of the Interior considered.accurate. 26/.

39-76658 595

These parameters include: (1) unit life of around 30 years; (?) peak production
of about 80,000 B/D oil and 90,000 MCF/D gas, assuming a normal production curve;
and, (3) total oil in place of from three to five billion barrels. Discrepancies
occur when projections of recoverable reserves are considered: USGS estimates
recoverable oil at 730 million to 1.1 billion barrels with a GOR of 500; the Oil
and Gas Journal published an estimate of one billion barrels; and, Exxon estimates
recoverable-oil at 400 to 500 billion barrels with a sales gas GOR of 1500.

A major inconsistency between production forecasts and recoverable reserves
now seems apparent. After Exxon released more information, the following production
scenario was derived: initial production from Platform Hondo would begin in 1978,
supplemented by production from the Submerged Production Systems on the Hondo pros-
pect in 1982; total Hondo production would peak. in 1985 at 60,000 B/D oil; and total
recoverable reserves after 25 years (to the year 2002) would be 243 MMB of oil and
365 BCF of gas (if gas were brought to shore). Further extrapolation of Exxon-
provided information indicates potential production from Sacate and Pescado would
begin in.1983; peak in 1985 with a resulting increase in total Santa Ynez Unit peak
production.of oil to 80,000 B/D oil; and recovering after 25 years (to 2006) around
176 MMB of oil (and 264 BCF of gas) for a unit total recoverable reserve of 419 MMB
of oil and 628 BCF of gas.

The difference of 300 to 700 million barrels of oil between the Exxon-derived
scenario and the recoverable reserve estimates of USGS has not been resolved during
the course of this study despite requests to both Exxon and USGS for clarification.
Among the more plausible explanations are: (1) Exxon finds new recoverable reserves
at regular intervals which were not calculated in its 419 MMB figure, thereby either
sustaining the 80,000 B/D oil peak rate of production; or, (2) the 419 MMB figure
reflects primary recovery only, and with enhanced recovery techniques the 730
million to 1.1 billion barrel range would be achieved. If the USGS low-range of
recoverable reserves is attained, a level of production reaching or exceeding 80,000
B/D oil and 90,000 MCF/D gas.could exist for up to 20 years, significantly affecting
the economics of transporting processed crude to refining areas. It is also con-
ceivable that Santa Ynez Unit production rates could reach as high as 200,000 to
300,000 B/D oil or 200 to 300 MB/D oil if a normal production curve over 30 years
was applied to recoverable reserves of 730 million to 1.1 billion barrels of oil
respectively. For a further discussion of Santa Ynez production rates see
Appendix 2.

PROCESSING. The Santa Ynez production may be processed offshore through use
of an OS&T or, provided the differences between Exxon and the Coastal Commission
can be worked out, onshore, The onshore site, a portion of a 1,500-acre parcel
owned by Exxon, is in Las Flores Canyon, about 20 miles west of Santa Barbara and
about 1 112 miles inland from the coast. The plant site covers about 15 acres of
land to be terraced and cut from canyon walls. In order to get permission from the
county to develop this site, Exxon had to secure a zone change and general plan
amendment. The new zoning affects a total of 66 acres, including the 15-acre
plant site, and extends into nearby Corral Canyon, suggesting that if expansion
were necessary, new equipment could be accommodated somewhere on the remaining
.51 acres. By contrast, expansion of the offshore alternative is not physically
possible on the OS&T anticipated. Should increased production occur, the
existing OS&T would have to be replaced by a larger one or an additional OS&T
would be required.

FUTURE DEVELOPMENT FOR THE SANTA YNEZ UNIT. The only development certain for

596

the Santa Ynez Unit is Platform Hondo. Exxon has also projected a need for two
Submerged Production System's (SPS), intended to operate in 900 to*1,500 feet of
water as satellites to the initial Hondo platform. Additional production facil-
ities for the Sacate and Pescado prospects are also contemplated in the Santa
Ynez development plan but are much more speculative at this time. The Sacate
Prospect is within reach of conventional platform production operations while
Pescado will require other deepwater technology.

Exxon has recently begun testing a guyed tower for production in deep-water
tracts such as Pescado. According to Exxon, "the guyed tower system may offer an
economically attractive alternative to conventional platforms for use in water
depths from 600 to 1,000 feet and an alternative to submerged production systems
from 1,000 to 2,000 foot depths." 27/ This appears to be a-logical substitute for
the 1,000 to 1,200 foot platform or-an SPS plus a surface support facility that was
originally considered.

Exxon proposes to link the five offshore facilities with a pipeline network
tied together at the initial Hondo platform. All production would then be commingled
and transferred by pipeline to the onshore facility or to the OS&T.

TIMING FOR FUTURE ACTIVITIES ON THE SANTA YNEZ UNIT. Platform Hondo will prob-
ably begin development drilling in late 1977, possibly beginning production by April
1978. Considering the uncertainties caused by the lawsuits affecting the Santa Ynez
Unit, all timing forecasts beyond these dates are hypothetical. The earliest pos-
sible settlement of pending cases could occur in the summer or fall of 1977, affect-
ing exploration and development phases minimall'y, possibly delaying production and
processing by at least one year. Assuming no significant delays, the secon.d and
third Hondo production systems could be set in place and begin development drilling
in 1981, with production starting in 1982.

Installation of the initial OS&T is scheduled for 1978, but pending court
actions may delay this proposal, and hence all production. Should the Las Flores
Canyon site be developed, construction time is estimated at two years, beginning no
earlier than six months following final court settlement. In no case is construction
likely to begin before 1978.
Further exploration of the Sacate and Pescado prospects will probably require
six wells and may take place before 1979. 28/ If development proceeds for Sacate
and Pescado, we assume a three-year interv-aT for design, fabrication, and assembly
of production components. Production facility installation would occur in 1982,
development drilling would be completed in 1983, and initial production would occur
in the same year.
Forecasts of production throughput for S-anta Ynez Unit facilities are shown in
Tables 4 and 5 of Appendix 2. These tables-assume the earliest possible settlement
of pending court cases and construction of the Las Flores Canyon facility, with
interim use of the OS&T until the onshore facility is completed.

HUENEME OFFSHORE

Operator: Mobil
Prospect: Hueneme
Exploration: complete
Development: proposed plan filed 1976
Production: 1980
Production System: one conventional platform

597

Processing: Two alternatives: (a) Mobil/Rincon
(b) new facility at Mandalay Beach
Transportation: onshore pipeline to Ventura, tanker and
pipeline options from there

The Hueneme Offshore field is located approximately three miles west of Port
Hueneme in Ventura County. The field lies in OCS-P-0202 and -0203, both acquired
in the 1968 lease sale by Mobil Oil and Union Oil jointly. Mobil is the designated
operator of both tracts and has submitted a development plan for the field to USGS. 29/

EXPLORATION. Exploration of the Hueneme field is essentially complete, with
nine wells drilled to date. No additional exploration activity is anticipated. 30/

DEVELOPMENT. Development of the Hueneme field as described in the plan of devel-
opment proposes installing one platform in waters around 100 feet deep with up to ten
producing wells. 31/ One rig would be used for all drilling, and all producing wells
would be drilled E-efore any crude oil and natural gas would be allowed to flow.

PRODUCTION. The Hueneme field is estimated to peak near 10,000 B/D oil and
200 MCF/D gas in the first year of production and to decline steadily thereafter,
with field life anticipated at around 20 years. 32/ These figures suggest total
recoverable reserves of around 20 MMB of oil and 4 BCF of gas.

TRANSPORTATION. Options for transportation include several pipeline alterna-
tives and barging. Barging is considered the least economic, to be used only as a
last resort, according to the unit operator. Pipeline alternatives vary, depending
on location of the processing site and on the possibility of combining Hueneme pro-
duction with production from the nearby Santa Clara Unit.

A limiting factor to transporting the Hueneme crude oil is its viscosity. Be-
cause the oil is unusually dense, much of the emulsif,ied water which would ordinarily
be removed at the platform may be left with the oil to improve pipeline flow. 33/
After processing, the crude would most likely proceed to refineries via the ma'r1ne
terminal operated by Union at Ventura, or through one of the pipelines connecting
Ventura with the Los Angeles area.

Gas produced from the Hueneme field would be used for energy requirements of
the platform and would not be transported to shore.

PROCESSING. Mobil intends to process Hueneme field crude oil at the existinq
Mobil-Rincon facility or at a new facility at Mandalay Beach. Surplus capacity at
Mobil-Rincon can accommodate this projected crude oil production, but to do so may
approach or exceed the present wastewater disposal capability of the plant. On the
other hand, development of a new facility at Mandalay Beach may be too costly
for Hueneme production alone, although sharing such a facility with Santa
Clara Unit operators appears significantly more feasible. 34/

FUTURE DEVELOPMENT FOR THE HUENEME FIELD. If the Proposed Plan of Development
for Hueneme is approved as described, tFe -one platform and a crude oil pipeline to
Mobil-Rincon would be constructed. The pipeline could deliver crude directly to
Mobil-Rincon or it could link with the existing pipelines delivering Dos Cuadras pro-
duction to the Mobil-Rincon plant. The former, direct pipeline, is preferable be-
cause it is the shorter route and avoids the complications and attendent risks of
joining with an existing submarine line.

598

TIMING FOR FUTURE ACTIVITIES ON THE HUENEME FIELD. If the plan is reviewed
in a timely manner, a decision could be reach-e-F-5-T-ate 1@777. If approved, con-
struction-plans would follow immediately. Allowing three years for design, fab-
rication, and assembly, development drilling and pipelaying could begin in 1980
with production beginning at the end of that year.

SANTA CLARA UNIT

Operator: Chevron
Prospects: Santa Clara (north field), south field
(unnamed)
Exploration: north field 60% complete, south field
less complete
Development: proposed plan for north field filed 1976
Production: 1980
Production Systems: 163 conventional platforms for north
field, unspecified for south field
Processing: four alternatives': (a) Chevron/Carpinteria;
(b) Mobil/Rincon; (c) new facility at
Mandalay Beach;, (d) OS&T
Transportation: tankers proposed

The Santa Clara Unit includes eight tracts in the Santa Barbara Channel, leased
in 1968* Tract ownership is divided among Standard Oil of California, Chevron, -
Exxon, Arco and Union, with Chevron as the designated operator. Exploration began
in 1968 and two potential fields were discovered by 1971. Union oil submitted an
application to USGS in 1971 to construct a Platform "Herb" on its lease overlying
the northern field; however, no action was taken and in 1973 the eight tracts were
unitized. With unitization, the Union proposal could not be considered apart from
a plan of operations for the unit. 35/ Chevron is now preparing a Plan of Develop-
ment for the unit.

EXPLORATION. Exploration for the eight-tract area has so far resulted in nine
wells, the earliest started in 1968, the most recent in 1976. Further exploration
projected by unit operators includes up to "two evaluation wells in 1977 and possibly
three more at a later date" for the north field, and an unspecified program for the
south field. 36/

DEVELOPMENT. Development activity to date consists of preparing engineering
designs for an initial platform and preparing a Plan of Development. The proposed
plan calls for developing the northern field with an initial platform to be installed
on Lease OCS-P-0216. Two additional platforms will be installed on -0217 and -0215
if justified by flow tests from the first platform. Northern field development would
require 46 to 116 wells drilled from the one to three platforms. Depending on fur-
ther exploration of the southern structure, development of this field would be com-
pleted by additional satellite production systems. 37/

PRODUCTION. Production from the unit is projected by the participants to begin
in 1981 and peak in 1982 or 1983. For the northern field, the participants estimate
proved reserves for the initial platform at 35 MMB of oil and 35 BCF of gas, with
another 73 MMB of oil and 93 BCF of gas should additional two platforms prove feasi-
ble. The southerly field may contain reserves of 70 MMB of oil and 113 BCF of gas;
however, the unit operator has less confidence in these latter estimates because
they are based on insufficient data. 38/

599

Under the single-platform scenario, Chevron projects a peak rate of production
at 16,000 B/D oil and 16,000 MCF/D gas for the year 1982. Assuming the three-
platform scenario, Chevron projects a peak rate of production at 38,000 B/D oil and
45,600 MCF/D of gas. With both north and south fields producing, we.project a peak
rate of production at 51,300 B/D oil and 72,800 MCF/D gas in 1986. 39/

TRANSPORTATION. Transportation of production to a processing site would be by
pipeline. Four alternative destinations are under consideration: three are onshore
and one is offshore (similar to Exxon's OS&T for the Santa Ynez Unit). The proces-
sing location will influence the method of transporting crude to refineries, since
only one site (Mobil-Rincon) is currently accessible by pipeline to refineries.
Chevron identifies Mobil-Rincon as a preferred site for processing but states that
it "plans to transship the crude by tanker to either/or both El Sequndo or Richmond
refineries. " 40/

PROCESSING. Processing could be achieved through one of four options:
(1) using the existing Mobil-Rincon facility; (2) using Chevron's existing facility
at Carpinteria; (3) installing a new facility in the Ventura-Oxnard area; and,
(4) processing offshore. Unit participants have shown some preference for the
Mobil-Rincon facility because "it is the most cost-effective,...enables Santa
Clara and Hueneme Unit to unitize a common subsea pipeline from platforms to shore,
...best conforms to zoning and land use requirements,...[and has] minimal environ-
mental and social impact." 41/ Chevron, however, also considers the Carpinteria
option attractive, and for This reason has not made a decision yet on which
plant will be finally selected.

Mobil"Rincon is capable of absorbing new production from the Santa Clara Unit.
Neither oil nor gas treating capacities will be exceeded. Since the unit operator
intends to:remove emulsified water from produced fluids to reach pipeline quality
standards (three percent water by volume) at the platform(s), wastewater disposal
limitations should not be exceeded as well. 42/

FUTURE DEVELOPMENT FOR THE SANTA CLARA UNIT. If Chevron's Proposed Plan of
Development is approved substantially as is, as many as three platforms would be
constructed and connected by pipelines to one of four alternative processing sites,
including one offshore. In view of the potential volume and timing of production
that could occur in the Santa Barbara Channel, it appears reasonable that Santa
Clara Unit production be pipelined to shore for processing at Mobil-Rincon. This
processing'solution is preferable because it involves the use of surplus capacity
at an existing facility, with a minimum amount of offshore pipeline. The Carpinteria
option would involve some expansion of that facility under full northern field
development. The Carpinteria option is less desirable than the Mobil-Rincon option
because, in the present situation, Carpinteria is dependent on marine transport for
delivering.crude oil to refineries. The Ventura-Oxnard solution is undesirable
because it involves constructing a new oil and gas facility near areas designated
for recreational use and conservation in local and state coastal management plans.
It would also require construction of a new pipeline through fragile coastal environ-
ments (Mandalay dunes, Ventura River estuary) to connect the processing plant with
crude oil transportation facilities in Ventura. The offshore alternative is con-
sidered unacceptable because of the increased-oil-soill risks posed by offshore
storage and transfer operations over onshore operations.

The Mobil-Rincon processing option would also promote unitization of an off-
shore pipeline to serve both the Santa Clara and Hueneme production operations.
Mobil-Rincon is already linked by existing pipelines to the Ventura area where

600

transporting processed crude to the Los Angeles basin could be accomplished by
existing pipelines, provided surplus throughput were made available. In the absence.
of pipeline transportation to refineries, Santa Clara production could create a
need for some three additional tanker loadings per month from existing marine ter-
minals during peak production in 1983.

TIMING FOR FUTURE ACTIVITIES IN THE SANTA CLARA UNIT. If Chevron's Proposed
Plan of Development is approved substantially as unit participants describe it,
the timing of future activities may occur as follows: two exploratory wells drilled
on the northern field in 1977; three additional exploratory wells drilled in 1978
or 1979; and, initial platform installed in 1979. Platform design was begun in mid-
4 1976, with fabrication and assembly for the initial platform projected to be completed
by 1979. If the field justifies three platforms, the second and third could be
installed in two-month intervals following the initial platform. The first produc-
tion wells could be in operation by late 1979,.with peak production in 1983. The
productive life for the three platforms is estimated to be around 22 years.

PITAS POINT

Operator: Texaco
Prospect: Pitas Point
Exploration: Continuing
Development: Plans (if any) not available
Production: 1982
Production Systems: One to two conventional platforms plus
supporting ocean-floor systems
Processing: Mobil-Rincon (probable)
Transportation: Same as Dos Cuadras

The Pitas Point Unit, still in the exploratory stage, consists of three tracts
located ten miles offshore from Santa Barbara. Two tracts are leased to the GTUM
group with Texaco as operator for both. The third tract was leased to Exxon, but
that lease has been allowed to expire.

EXPLORATION. Far less is known about Pitas Point development potential than
any of the preceding fields described. Texaco's two initial exploratory wells were
inconclusive and-a third well has been recently completed. 43/ Each of the three
wells have looked for potential reservoirs at depths greatJ7than 15,000 feet,
deeper than any other potential reservoirs now being considered for development in
the Channel. Knowledge gained from the recent exploration could indicate whether
the field is commercially productive or not. Further exploration beyond this well
could also be required.

DEVELOPMENT. -Development of the Pitas Point Unit depends on further evaluation
of exploration [email protected] Yet the-potential development of this area commands more
than a casual Interest if the bonus paid for a lease is any indicator: the lease
to OCS--P-0234 was acquired for $56,378 million, second only in the 1968 Channel
lease sale to the $61,418 million-paid for the nearby OCS-P-0241 in which the Dos
Cuadras field is being produced.

PRODUCTION. Production of the field is difficult to predict since no informa-
tion has been published or volunteered.by Texaco on recoverable reserves or pro-
duction rates. 44/ The only published information on the unit is the perhaps
optimistic commi-ntary in a recent trade journal. that "one to two new platforms with
supporting submerged production systems" could be positioned on the field if the

601

current well being drilled is successtul. 45/

TRANSPORTATION. If the discovery is found to be commercial, oil
and gas would be pipelined to shore for processing. GTUM facilities would
logically be considered first in formulating transportation and processing options.
Existing GTUM facilities i-n the area include the Union-operated Dos Cuadras field,
platforms, the pair of twelve-inch pipelines connecting these platforms with the
onshore Mobil-Rincon processing plant, the Mobil-operated pipeline from Rincon to
Ventura, t 'he Union/Ventura marine terminal, and the Union and Texaco pipelines that
connect Ventura to Los Angeles. Production from Pitas Point could flow through a
four-mile pipeline to Platform A, which already serves as a gathering platform, and
then through the existing pipelines to shore. Alternatively, a new ten-mile PiDe-
line could be laid directly to Mobil-Rincon. Past Mobil-Rincon the transportation
options are the same as described in the Dos Cuadras scenario.

PROCESSING. Mobil-Rincon is likely to be proposed as the processing facility,
with an offshore alternative reserved in the event onshore processing is not
possible. Assuming production is initiated in 1981, Pitas Point oil and gas pro-
cessed through Mobil-Rincon could exceed current design capacity after 1982. We
estimate that any expansion required to accommodate this increase in production
could be accommodated within the already-developed 14 acres of the 140-acre site.

FUTURE DEVELOPMENT FOR THE PITAS POINT UNIT. If Texaco's evaluation of recent
exploration proves the field to be commercial, development plans could begin to be
formulated soon. Considering the depth and size of the field we conclude that two
platforms positioned in OCS-P-0234 are plausible. Further, it would be logicalfor
Pitas-Point production to be processed at Mobil-Rincon. In order to get to Mobil-
Rincon, we conclude that the existing Dos Cuadras-to-Mobil-Rincon pipelines should
be used because of significant available surplus capacity (in excess of 60,000 B/D
oil and 80,000 MCF/D gas in the 1980s). This option is preferred over that of
constructing a new pipeline directly to shore. Note, however, that increased
throughput at Mobil-Rincon resulting from Pitas Point production could necessitate
expansion of that facility in the mid-1980s.

TIMING OF FUTURE ACTIVITIES IN THE PITAS POINT UNIT. If Texaco's recent
exploratory well is successful, we assume that an additional two to three confirma-
tion wells would be required and could be undertaken in 1977-78. Allowing three
.years for@platform design, fabrication, and assembly, the two platforms could be
instal.led in 1981, with initial production by 1982.

SAN PEDRO BAY

Operators: Chevron, Shell, Gulf, Texaco, Mobil,
Challenger
.Prospects: One confirmed discovery, several others
to be explored
Exploration: Continuing
Development: Shell currently evaluating
Production: 1980s
Production Systems: None specified yet, conventional platforms
preferred by companies
Processing: Onshore options available, Shell has
suggested fixed offshore structure
.Transportation: Onshore pipelines

602

Tracts leased in San Pedro Bay are thought to contain the best prospects
offered in Lease Sale #35. Since the lease sale in December 1975, industry has
applied for exploratory drilling permits on 12 of the 13 leases. Exploration
began in July 1976; 15 wells have been completed as of May 1977. From these
initial wells, cautious reports on-one discovery have been made and at least one
estimate for recoverable reserves has been suggested. 46/

Ownerships in the federal OCS of San Pedro Bay include bidding groups led by
Shell, Chevron, Gulf, Texaco, Mobil, and Challenger Oil. Shell and Chevron are
the designated operators for four 'tracts each; Gulf operates two; and, the remain-
ing three group leaders each operate one lease. Lease ownership is shown on
Figure 7 of Chapter 19.

EXPLORATION. Shell has drilled eight wells on its four leases in San Pedro
'Bay as of May 1977. Chevron has drilled another seven, all in one tract. At
least some of these wells have reported oil-bearing sands with some apparent com-
mercial potential. Fourteen of the wells are on the same structure. Four other
structures within the bounds of existing leases remain to be explored.

DEVELOPMENT. Development planning for San Pedro Bay is likely to begin this
year when Chevron and Shell complete their separate evaluations of the wells they
have drilled. A possible plan of development for the current discovery area (tracts
254, 261, and 262 on Figure 7, Chapter 19) could be ready for review by the Depart-
ment of the Interior by 1978. Production equipment, depending on its availability,
regulatory approvals, and industry incentive, could be installed anytime between
1978 and 1980.

The initial reservoir has been found in depths less than 4,000 feet below the
ocean floor by drilling vessels operating in 175 to 659 feet of water. The
water depths suggest.that if Chevron and Shell proceed with development plans,
conventional fixed platforms, may be proposed. Based on the geographic extent of
the prospect, its relative shallowness, and the location of the exploratory wells
drilled to date, we predict that up to four platforms would be proposed by
Chevron and Shell.

Further development in San Pedro Bay will-depend on additional exploration,
since several other prospects have yet to be explored. For total development,
USGS estimated San Pedro Bay could justify two to nine platforms.

PRODUCTION. Production estimates for San Pedro Bay are extremely limited.
Based on USGS estimates, current leases in San Pedro Bay are capable of economi-
cally recovering 355 to 946 MMB of oil with a GOR of 850. 47/ According to two
independent petroleum analysts, the Shell discovery is estimated to contain 300-
400 MMB recoverable oil. 48/ Based on typical offshore field performance, the
current discovery then co-uld be expected to peak around 80,000 B/D oil and, using
USGS's GOR of 850,.we would expect 70,000 MCF/D gas to be produced as well. If
we assume 946 MMB oil and 821 BCF gas are recoverable, it is likely this Volume
will be produced from several prospects. Since individual field peaks-would
@probably be staggered, we project an area-wide peak level of production at
around 160,000 B/D oil and 140,000 MCF/D gas. Area-wide average dafly production
would-be around 601,000 barrels of oil and 50,000 MCF of gas.

TRANSPORTATION. 'Transportation by pipeline is likely to be favored by
industry because of*the field's proximity to the well-developed Los Angeles Basin

603

pipeline network serving the many refineries in Los Angeles County. Since all
the OCS designated operators in San Pedro Bay, except for Challenger, own nearby
oil and ga,s facilities, onshore processing plant sites are also likely to be
available.' In particular, Gulf and Chevron already have processing plants, and
own suitable, undeveloped land in Huntington Beach.

Facilities in the harbor areas owned or operated by San Pedro Bay lease-
holders include: Union* Oil Refinery, Wilmington; Union Oil Bulk Terminal in the
Outer Los Angeles Harbor, San Pedro; Mobil Oil marine terminal and storage facili-
ties on Terminal Island; Chevron marine terminal and storage in San Pedro; Shell
Oil marine terminal and storage at Slip 1, Wilmington; Gulf Oil marine terminal and
storage on Terminal Island; Texaco marine terminal near Channel 2 in Long Beach;
and, the THUMS operation (Texaco, Humble (Exxon), Union, Mobil, and Shell) for the
Long Beach Unit on Pier J, Long Beach. Chevron, Shell, Texaco, Mobil, and Gulf
have refineries in other parts of the Los Angeles Basin (see maps in Appendix 3 for
a location of these refineries).

An extensive pipeline network connects the harbor areas with refineries
throughout the Los Angeles area. Huntington Beach is also linked to refineries by
pipelines. Either location could satisfy processing requirements while facilitat-
ing pipeline transportation to local refineries.

PROCESSING. Since Chevron and Shell will most likely be required to unitize
operations on Leases 254, 261, and 262, where they are now delineating the current
discovery, they will need one processing site for this area. This site could be in
the harbor areas or Huntington Beach or offshore. We conclude on the basis of
total estimated recoverable reserves, San Pedro Bay OCS tracts will not require
more than one additional treatment and separation site.

FUTURE DEVELOPMENT FOR THE SAN PEDRO BAY OCS AREA. If the recent di"scovery
on leases 254, 261, and 262 is as productive as some indicators suggest, four plat-
forms could be proposed, with.pipelines connecting them to an onshore processing
plant in Huntington Beach or Long Beach Harbor. Additional development is likely
to occur, but its extent-is unknown. USGS has suggested that up to five additional
platforms could be required.

Partly because of congestion problems caused by ship traffic in the San Pedro
Bay area, the State of California requested that this area not be leased by the
federal government and that structures not be permitted in the vessel traffic
separation scheme (VTSS) 49/ The Department of the Interior has not-accepted similar
recommendations by the St-ate for denial of drilling permits in the shipping lanes:
exploration has taken place and development would appear to be inevitable.

In order to minimize risks involved in developing this area, we propose that
industry substantially complete exploration of all prospects in San Pedro Bay
before proceeding with any development. After weighing all potentially recoverable
reserves against the attendant risks of recovery, the operators should prepare a
development plan which coordinates timing and location of all facilities and mini-
mizes the number of surface production systems in the Bay. We further recommend
that any production that must be located within the VTSS be submerged, ocean-floor
systems.

*Union is a joint-owner of one lease with Chevron.

604

Onshore processing should also be considered in the area-wide plan. Possibil-
ities include converting existing facilities used for onshore production, expanding
the THUMS operation, and constructing new facilities. Design of the new processing
plans should accommodate the projected throughput for the 0254/0261/0262 discovery
and should also evaluate the feasibility of expanding throughput capacity to handle
additional San Pedro Bay OCS production. If an initial plant could not feasibly
accommodate this total production, a second plant migh t be justified.

TIMING FOR FUTURE ACTIVITIES IN THE SAN PEDRO BAY OCS AREA. We project up to
four drilling rigs to drill approximately twelve exploratory wells will be present
in 1977. In 1978, this could be reduced to two drilling rigs completing another
five to six exploratory wells. Unless development of the entire area is planned
simultaneously, there is strong likelihood of an incremental buildup, possibly with
as many as nine platforms by the early 1980s'.

L E A S E D A R E A S W I T H 0 U T D I S C 0 V E R I E S

Leased areas without discoveries incl.ude 36 tracts in the Santa Barbara Channel,
43 tracts in the Outer Banks areas, and 10 tracts in San Pedro Bay. In the Santa
Barbara Channel, exploration without discovery has resulted in some tracts being
quit-claimed, while others are still being evaluated. In the Outer Banks, explora-
tion has just begun.

Exploration for all of these areas has accelerated in 1977. Of the 43 tracts
comprising the Outer Bank leased areas, 31 have received permits for exploration
from the Corps of Engineers. Of the Santa Barbara Channel's 36 leases without
discovery, 12 have received drilling permits'following approval of the Santa
Barbara Channel EIS in 1976. Additional exploratory drilling permits in both areas
can be anticipated.

In formulating scenarios for leased areas without discoveries, the only
assumptions we have relate to undiscovered recoverable reserves and to the number
of production systems possibly required.

For the Santa Barbara Channel USGS estimates that 40 to 200 MMB oil and 20
to 100 BCF gas could be recovered in leased areas without discoveries. The areas
include the Oak Ridge Unit, the San Miguel Unit, the Santa Cruz leases, the
Anacapa leases, the Pauley leases, leases east of San Miguel, and four mid-Channel
tracts owned by Exxon. These areas are shown on Figure 3 of Chapter 19. For
these 36 leases, $221,439,971 was paid, slightly more than one-third of the amount
paid for all 71 leases sold in the 1968 Channel sale. Since no area-specific
information is available, assumptions regarding the location and size of undis-
covered recoverable resources in the Channel are not possible.

Even less is known about the Outer Bank areas than leased areas without dis-
coveries in the Santa Barbara Channel, the latter areas having benefited from
several years of exploration and production in-nearby leases. Each Outer Bank area
is located in geologic provinces not associated with the Channel or San Pedro Bay
and, until recently, none had been explored by deep wells. The first exploratory.
drilling has just begun in the Santa Rosa-Cortes South (Tanner Banks) area.

If and when recoverable reserves are discovered in the Outer Banks, a critical
factor in determining the magnitude and nature of effects onshore will be the

605

transportation method used to bring production to shore. An analysis of transpor-
tation costs of pipeline vs. surface transport for southern California OCS oil
concludes that: "For the Santa Rosa-Cortes North site, the shallow water pipeline
is the least costly alternative at both the high and low-estimates of reserves....
For the Santa Barbara-Santa Catalina site, the pipeline alternative is clearly the
most cost-effective alternative at both the low and high-estimates of reserves.
For the Santa Rosa-Cortes South site, which is the farthest site from shore, the
tanker is the most cost-effective alternative at both the low and high-estimates
of reserves." 50/ The analysis also states: "Pipelines are safer by a factor of
seven in the case of Santa Rosa-Cortes (North)...by a factor of five in the case
of Santa Barbara-Santa Catalina...by a factor of 6.5 in the case of Santa Rosa-
Cortes (South)." 51/

Figure 7 shows the various pipeline and tanker routes considered by Booz-Allen.
This analysis was prepared before the lease sale was held and without knowing which
tracts would actually be leased. The analysis does not sufficiently compare the
following alternatives or evaluate several important considerations: it does not
compare the effects of sharing the pipelaying costs for produced oil with the pipe-
laying costs for produced gas if the two pipelines were laid together; it does not
evaluate the risks of oil spills from storage facilities required by tankers; the
pipeline routes used do not follow the shallowest routes possible; a pipeline route
between Santa Barbara Island leases and Ventura County is not considered; each
pipeline is assumed independent of the others; it is not clear to what extent, if
at all, offshore treatment and separation was considered; the environmental costs
of tankering vs. pipelining are not considered.

In light of the uncertainties regarding optimum transportation and processing
of Outer Banks production, and the potential risks and unnecessary costs attendant
with incremental and disjointed development, it should be clear that a thorough
exploration program for each of the Outer Banks should precede any planning for pro-
duction, transportation, and processing in these areas. If recoverable reserves
within the limits estimated for the respective areas are confirmed, an offshore
pipeline system could be designed to avoid water depths exceeding 1,350 feet. The
combined length of the primary trunklines would be approximately 200 miles (see
Figure 2).

U N L E A'S E D A R E A S T H A T C 0 U L D B E 0 F F E R E D I N
L E A S E S A L E #4 8

In the following chapter we discuss in greater detail the prospects of Lease
Sale #48 for southern California. Although this sale has been deleted from the
current schedule for offshore leasinq, there is still a strong possibility it will
be offered by 1980. The Department of the Interior is continuing its efforts to
prepare an EIS for this sale and has tentatively selected tracts to be offered.
These tracts were selected on the basis of public and private-sector nominations --
many of which conflict. Notably, the Santa Barbara Channel received the
most positive nominations and the most negative. San Pedro Bay and the San Diego
Coast were each heavily nominated both positively and negatively, as well. The lo-
cations of positive, negative, and tentatively selected tracts for Lease Sale #48
are shown in Figures 2, 3, and 4 of Chapter 22. In the "Lease-Area Planning" sec-
tion of Chapter 19 we outline some of the concerns that need to be addressed by the
Department of the Interior before and after any of these areas are offered for
lease.

In the following few paragraphs we reiterate some of the concerns identified

606

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in Chapter 19 and postulate a range of new development that could occur as a
result of leasing these areas. These projections can be viewed only as extremely
speculative by their nature as they are based on suppositions regardinq a very
uncertain lease sale proposed for a very uncertainfuture.

SANTA BARBARA CHANNEL LEASE SALE #48 NOMINATIONS

The unleased area of the Santa Barbara Channel federal OCS represents approx-
imately 95 tracts. At the time of the 1968 lease sale, 44 of these tracts were
not offered, primarily because of excessive water depths, while the rest were
offered but did not receive bids or the offers received were rejected. The Call
for Nominations for the Proposed Lease Sale #48 resulted in all available tracts
in the Channel.being nominated. Tentatively, BLM has selected 76 tracts in the
Channel,.plus an additional 33 tracts to the west of Pt. Conception for inclusion
in Lease Sale #48. The combined total of 109 tracts is almost identical in
number to the 110 tracts offered in the 1968 lease sale. In that sale, 75 tracts
received offers, and of these, 71 were accepted.

Of the 109 tracts that may be offered in Lease Sale #48, two-thirds are
located in water depths exceeding the capability of conventional fixed-structure
platforms. If these tracts are leased and subsequently proved to contain
economically recoverable resources, we project thatthey will be developed
with ocean-floor production systems such as Exxon's Submerged Production System
proposed for the Santa Ynez Unit. Such systems are preferable to surface
str@ctures that.would otherwise pose potential navigational risks in the
Channel.

SAN PEDRO BAY LEASE SALE #48 NOMINATIONS

BLM has tentatively selected 22 tracts in San Pedro Bay for Lease Sale #48.
All 22 were offered in Lease Sale #35 but either received no bids (15 of the 22)
or received bids that were rejected by BLM as being too low (7 of the 22).

Assuming these tracts are offered,.we would expect that less than half of
them will be leased. If leased, their exploration would coincide with the first
development and production operations that we projected for existing San Pedro
Bay leases that resulted from Lease Sale #35 (i.e., 1980). If these newly leased
tracts are found to contain economically recoverable oil and gas, we assume new
production facilities would be required but supporting onshore development could
be kept to a minimum if that which is developed for the Lease Sale #35 tracts
were made available.

OUTER BANKS LEASE SALE #48 NOMINATIONS

For the three Outer Bank areas, BLM has selected 60 tracts for inclusion in
proposed Lease Sale.#48. Most of these tracts were offered in Lease Sale #35
but were not bid on or received bids that were rejected by BLm as being too low.

Exploration to date in the Tanner Banks has produced discouraging results
leading some leaseholders to cancel already-planned exploration programs. Because
of the very sparse information available on the Outer Banks, all that can be
said about future development resulting from Lease Sale #48 is that the chances
for any development at all may simply increase.

608

SAN DIEGO COAST LEASE SALE #48 NOMINATIONS

Although the San Diego coast offshore area was eligible for nominations'in
Lease Sale #35, no tract received a nomination at that time. As a result of the
Call for Nominations for Lease Sale #48, however, positive nominations were
received uniformly from Point Fermin to the Mexican border, extending seaward up
to 25 miles beyond the three-mile offshore limit of state-federal jurisdiction.
BLM has selected approximately 27 tracts from Dana Point to the international
boundary for tentative inclusion on Lease Sale #48. Most of these tracts are in
deep water; and we judge that only two tracts could possibly be developed from
conventional, fixed-structure platforms (both would be in the 900-foot range).
The remainder of the,tracts, would require deepwater technology such as compliant
towers or ocean floor production systems.

If Lease Sale #48 is held and this area is offered, it would init iate the
first OCS-related activities along this stretch of coastline. There'"is presently
no onshore or staite tidelands oil and gas development in thJS area, and the only
existing petroleum-related activities include San Diego Gas and Electric's marine
terminal operation at Carlsbad for offload.ing fuel oil and a pipeline from the
Los Angeles area delivering jet fuels and other refined products to the Navy and
other users in the San Diego area. If San Diego coast offshore leases prove to
contain economically recoverable -resources, it is likely that onshore industrial
uses, including processing plants, supply bases, and crew staging areas, will be
required to.support them. We project that from one to five processing plants
and from one to three crew staging and support bases could be required. The
location and scale of development *will depend on the location and amount of re-
coverable reserves and other variables, including environmental regulation. If
natural gas is discovered, it can be sold directly into major gas transmission
lines that parallel the coastline, and relatively little new construction may
result. If crude oil is discovered, it will require either the construction of
a new pipeline to the Los Angeles basin or one or more marine terminals to permit
barging or tankering to the same area.

609

FOOTNOTES

l. M. R. J. Wyllie, Vice President, West Coast Division, Gul,f Energy
and Minerals Company -- U.S., letter to Bill Deller, Office of Planning and
Research (OPR), October, 27, 1976.

2. R. B. Read, Editor, letter to Allan Lind, OPR, May 1, 1977.

3. See "Unitization" in Chapter 19 for an elaboration on this point.

4. Hillary A. Oden, Acting Conservation Manager, Western Region, Geological
Survey, letter to Office.-of Planning and Research,. Attention: Suzanne Reed,
June 22, 1976.

5. Personal communication from-Ben C. Piester@ District Superintendent,
Phillips Petroleum Company, to Allan Lind, OPR, July 7, 1976.

6. Personal communication from Maurice V. Adams, Staff Petroleum Engineer,
Geological-Survey, to Allan Lind, OPR, August 4, 1976. Sun's proposal was to
build an onshore processing plant to handle production from the soon-to-be-
installed Platform Hillhouse on the Dos Cuadras Offshore field. Sun was denied
a permit to.construct this facility by the Ventura County Board of Supervisors
who encouraged Sun to consolidate its production requirements with Union, -
operating another portion of the Dos Cuadras field, and to consolidate its.
processing requirements at the existing Mobil/Rincon plant where Dos Cuadras.,
production was already being handled. Sun eventually carried out these suggestions'.

7. Piester, op. cit.

8. Hillary A. Oden, letter to Suzanne Reed, OPR, October 6, .1976.

9. Ibid.

10. Oden, op. cit.

11'. Personal communication from'Richard Voils, Projects Engineer,.Mobil
Corporation, to Allan Lindi OPR,"July 28, 1976.

12. Ibid.

13. Wyllie, op. cit.

14. Voils, op. cit.

15. Oden, op. cit.
16. See Appendix 2.-for production rate estimates made@by OPR:staff from
data supplied by the various offshore operators.
17. Discovery dates for all but the.San.Pedro field are from Final Environ-
mental Statement, Oil and Gas Deve-lopment-in the Santa Barbara Channel Outer
Continental Shelf Off California, U.S. Department-of the.Interior, Geological
Survey, 1, 1976, pp_ii-14@ The San Pedro Bay.discovery-was reported-in
Offshore Magazine (August, 1976), 120.

610

18. See Chapter 14 and Appendix 2,for further discussion of Santa Ynez Unit
resource potential.

19. From a map titled "Map Showing Oil- and Gas Fields,-Leased Areas, and
Seeps in the Santa Barbara Channel Region," Scale 1:250,000. Department of
Interior, Geological Survey, Washington,, D.C., 19699 G70137. Map is also noted
as Plate 2, Professional Paper 679.

20. "Southern California Offshore Lease Map With Oil & Gas Fields,." Exxon
Company, USA, April 1, 1976.

21. Pers onal communication-from Darrell Warner, Division Operations Manager,,
Western Division, Production Department, Exxon Company, U.S.A., to Trevor
O'Neill,.OPR, August 29, 1976.

22. Exxon Company, U.S.A., Supplemental Plan of Operations Santa Ynez Unit,
I (Introduction), revised, c. '1973, p. 21.

23. These numbers ass-ume a GOR of.1500 for sales gas. See Appendix 2 for
further details. Numbers based on personal, communication from Darrell Warner,
Exxon, to Trevor O'Neill, October 27, 1976.

24. Exxon Company, U.S.A., op. cit., I, p.- 22.

25. Since the design of this facili.ty, Exxon has raised its estimate of
the GOR to 2500, with 1500 being sales gas. We.would assume that., if the Las
Flores Canyon plant is constructed, certain modifications to the original design
may be necessary.

26. Exxon's Supplemental Plan of Operations,.Interior's FES, Santa
Barbara Channel, and Interior's FES, Santa.Ynez Unit (1974). aqree on the
parameters listed.
27. Offshore.Magazine, Volume 36, No. 8 (July 1976). 55.

28- Warner, 2p. cit., August 29, .197.6.

29. W. D. Fritz, Acting Producing Manager,.Los Angeles Producing Area,
Mobil Oil Corporation, letter to David Calfee, OPR, October 21, 1976.

30. Personal communication from W. D. Fritz to OCS Project staff,
October 18, 1976.

31. Ibid.

32. Ibid.

33. Ibid.

34. Ibid.

35. Oden, op. cit., June 22, 1976.

40--76658 611

36. Personal communication from Thomas A. Hudson, Supervisor of Offshore
Planning, Western Operations, Chevron Company, USA, to OCS Project staff,
September 28, 1976.

37. See Appendix 2, Table 3.

38. Hudson, op. cit., September 28, 1976.

39. Ibid.

40. Ibid.

41. Ibid.

42. Ibid.

43. Offshore Magazine, October, 1976.

Questionnaires regarding such information were sent to all major OCS
operators, and each responded except Texaco-. Texaco informed OPR that it was
unable to respond to the questionnaire for reasons they chose not to explain.

45. Offshore Magazine, Volume 36, No. 11 (October 1976), 115.

46. Los Angeles Times, October 20, 1976.

47. See Chapter 14.

48. L.A. Times, loc. cit.

49. See, for example, letter from Preble Stolz, Director, OPR, to BLM,
October 14, 1975; letter from Bill Press, Director, OPR, to Bill Brant, Pacific
OCS Manager, BLM, September 14, 1976.

50. Booz-Allen & Hamilton, Inc., A Ris-k and Cost Analysis of Transporting
Southern California Outer Continental -STel-f Oil, July 3, 1975, pp.. 3-5.

51. Ibid., p. 5.

612

CHAPTER 22

LEASE SALE #48:
BEGINNING AGAIN

BACKGROUND

C A L L F 0 R N 0 M I N A T 1 0 N S

On July 16, 1976, seven months after completing southern California OCS
Lease Sale #35, the Bureau of Land Management issued a Call for Nominations for
southern California Lease Sale #48. 1/ The area covered by the Call included the
offshore southern California area already considered in OCS Lease Sale #35, plus
the-San'ta Barbara Channel. In all,,2,400 tracts encompassing 13.2 million acres
between Point Conception and the Mexican border were tentatively proposed for in-
clusion in the sale (see Figure 1), scheduled to take place in March, 1978.

In response to the Call for Nominations, California State and local govern-
ments submitted "negative nominations" opposing leasing in specified offshore
areas, based primarily on concerns over:

1. air quality impacts;
2. oil spill risks;
@3. threat to areas.of special biological significance and ecological impor-
tance;
4. conflicts with navigation;
5. lack of adequate information concerning the extent of oil'and gas
resources or potential for damage to environmental, recreational, and
aesthetic resources;
6. cumulative effects of OCS development combined with a number of other
major energy activities proposed for the California coast;
7. lack of adequate assurance that OCS exploration and development would be
conducted in a manner consistent with California's Coastal Zone Manage-
ment Program; and,
8. need for amendment of the OCS Lands Act, in order to provide adequate
environmental safeguards and a greater rol-e for state and local govern-
ments in leasing and development decisions. 2/
Tracts recommended for exclusion from the OCS Lease Sale #48 area included:

1. all tracts excluded for environmental and geologic reasons from Lease
Sale #35, including:

613

a. Santa Monica Bay:
b. tracts south of San Miguel Island;
c. nortions of tracts adjoinina state Jurisdiction offshore of the
Palos Verdes Peninsula, Long Beach, and all of Orange County; and,
d. four tracts in the Outer Banks areas designated as tracts with
high geologic hazard;
2. all tracts located within three miles of the three-mile state tidelands
boundary;
3. all unleased tracts in the San Pedro Bay;
4. all tracts intersected by vessel traffic lanes and separation zones; and,
5. all tracts wholly or partially overlying bank areas of recognized ecolo-
gical value.

These negatively nominated areas are shown in Figure 2.

Representatives of several local governments whose coastal areas would
be potentially affected by Lease Sale #48 also submitted negative nominations and
expressed views on tract selection for consideration by BLM.

The County and City of Santa Barbara recommended deletion of all tracts in the
Santa Barbara Channel and surrounding the Channel Islands. 3/ Supervisor Hayes, of
the County of Los Angeles, recommended extending the Santa ffonica Bay exclusion
area and deleting all tracts surrounding Santa Catalina Island and lying between
the Island and the mainland. 4/

The City of Newport Beach, in Orange County, registered its opposition to any
further leasing of offshore southern California until technological advances siqnifi-
cantly reduce the risks to recreational resources inherent in OCS development. 5/

The County of San Diego recommended deletion of all tracts within approximately
fifty miles of the Los Angeles, Orange, and San Diego County coastlines. 6/ A
similar recommendation was submitted (November 19, 1976) by the Comprehen-sive Plan-
ning Organization of the San Diego Region 7/ and by the San Diego Coast Regional
Commission. 8/ In addition, San Diego's Mayor Wilson negatively nominated tracts
within the THrty- and Forty-Mile Bank areas off San Diego. 9/

Many of the areas identified by state and local government as particularly
sensitive to oil and gas development correspond with tracts specified as high-
interest areas by industry. Seventeen oil companies positively nominated 970 tracts
totalling over five million acres. 10/ Those areas receiving greatest industry
response were in the Santa Barbara Uhannel, offshore San Diego, San Pedro Bay, and
,the Outer Banks (see Figure 3).

T R A C T S E L E C T 1 0 N

In October, 1976, the Pacific Coast office of BLM held an "environmental brief-
ing" for state and local representatives, in which highly generalized and dated
information concerning the proposed lease area was presented orally. In late
November, the Pacific Coast BLM office invited state representatives to attend a
meeting on December 2, 1976. to discuss tract selection recommendations for Lease
Sale #48. ll/ Local representatives were notified of the meeting by telephone the
day before--f-t took place. At the meeting, the information was presented verbally,
in summary fashion. BLM refused to provide state and local government representa-

614

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tives with the Pacific Coast officels wrttten tract selection recommendations pre-
pared for the Washington offices of BLM and USGS in spite of two written requests
from the State. 12, 13/

State and local government representatives were invited to attend a tract
selection meeting in Washington, D.C., scheduled for two weeks after the Pacific
Coast office presentation. 14/ However, lacking written recommendations to which
they could respond substantWely, California state and local governments were ill-
prepared to participate. The State responded in writing, reiterating previously
expressed concerns and pointing out that a majority of the federal agencies pro-
viding BLM with resource reports on the Lease Sale #48 area had raised concerns
similar to those of California.state and local governments. 15/

The Director of the Departme nt of the Interior's Bureau of Outdoor Recreation
(BOR) characterized the southern California coastal and offshore area as "one of
the best known and most heavily used recreation and resort destinations in the
United States." Describing the entire southern California coastal and offshore
area as a recreational resource of "special significance," BOR emphasized that the
"special significance intensifies around the Channel Islands, inshore waters,
shoreline, estuaries, and accessible stretches of coast in the vicinity of popula-
tion centers and resort destinations." 16/

The National Marine Fisheries Service, 17/ the Fish and Wildlife Service, 18/
.and the Marine Mammal Commission 19/ characterized the southern California bays,
wetlands, estuaries, and offshore rocks and waters as important habitats for
commercial and sport fish, marine birds, and marine mammals. Many species of
birds and mammals found in these areas are rare-or endangered, including the brown
pelican and seven species of cetaceans. Each of these agencies emphasized the
especially unique qualities and sensitivity of the Santa Barbara Channel marine
species habitats. Fish and Wildlife reaffirmed its view, as expressed in response
to Lease Sale #35, that an

.ecological buffer zone should be established around all the Channel
islands, especially San Miguel Island and Santa Barbara Island, in
order to protect them from the possible adverse effects of OCS leasing
and development.

The Marine Mammal Commission recommended that further leasing in the Channel
be delayed'until environmental baseline studies are completed and a better under-
standin of the.potential for OCS activities to affect marine mammal population@
adverMy is reached. The Commission also recommended that-the three-mile
buffer zone afforded by state territorial waters around San Miguel, Santa Rosa,
and most of Santa Cruz islands be augmented by a three-mile.federal buffer zone
in order to protect pinniped and cetacean habitats.

The Environmental Protection Agency recommended that the entire Santa Barbara
Channel be deleted from the lease sale because of the "hazardous DOtential" for
adverse effects from OCS leasing and development. 20/ The National Park Service
expressed its desire to protect cultural resources of the southern California off-
shore area, especially the 33 archeological sites, i.ncluding nine possible early
village.sites known to exist off the southern California coast. 21/

On January 18, 1977, BLM announced the selection of 217 tracts to be examined
in the OCS Lease Sale #48 Environmental Impact Statement. 221 Although some of

618

the tracts negatively nominated by California state and local government were ex-
cluded from consideration, the apparent reason for this was lack of industry interest.
On the other hand, the entire Santa Barbara Channel, for which state, local, and
federal opposition to leasinq is the greatest, was selected (see Figure 4).

E N V I R 0 N M E N T A L I M P A C T S T A T E M E N T

The Bureau of Land Management began to prepare the Lease Sale #48 Environmental
Impact Statement in early 1977 by co.ntact".ng state and local representatives to in-
vite participation in drafting the Lease Sale #48 Environmental Impact Statement. 23/
The draft EIt was scheduled for publication in late 1977, with the final EIS sched-
uled for publication early next year just prior to the March, 1978, lease sale date.
Local and state government representatives responded with recommendations as to how
their participation might be structured. 24, 25/ This response included renuests
for:

1. the Department's budget for Lease Sale #48, inc luding allocation for staff
and contractual services among various subject areas, and,
2. financial assistance to local governments in order to support independent
reviet,1 and analysis of the EIS.

In addition, this response recommended that:

1. an Executive Summary of the EIS be DreDared and widely distributed;
2. the EIS consider in detail energy alternatives to OCS development and
.indicate the actual effect on the energy supplies of deleting various
tract offerings such as the- Santa Barbara Channel or the area immediately
.offshore San Diego;
3. BLM use a more suitable method for analyzing economic impact at the sub-
reoional level than-it currently planned, and that such analysis consider
the economic effects of deteriorated air auality and oil spills;
4. BLM place considerable emphasis on oil soill impact analysis and recon-
sider whether the EIS is using the most suitable trajectory model
available;
5. BLM reconsider its proposed air quality imDact assessment in light of
the need for better data and more time to develop a credible and useful
analysis; and,
6. the EIS address in detail potential conflicts between military operations
based on the southern California coast and OCS develODment.

Because the City of-San Diego also filed suit aqainst the lease sale, the
Department was hesitant to respond in wri*ting to local government requests for in-
formation on the EIS.

R E L A T 1 0 N S H I P T 0 L E A S E S A L E 3 5 A N D T 11 E
N A T I O@N A L 0 C S L E A S I N 6 S C H E D U L E

State and local concerns over Lease Sale #48 are similar to those exDressed
over Lease Sale #35, which is now the subject of litigation between the State of
California and,the Department of the Interior. ResDondinq to some of these con-
cerns in 1975, the Department of the Interior stated its intention to:

1. resolve confusion over regulation of OCS drilling in shippinq lanes in
. order to minimize threats to navictation; 27/ and,
2. commence pipeline corridor studies in cooperation with state and local

619

Gaviota Capitan
Figure
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Baach

SANTA
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11

A
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NORTH SCALE 1:1 ACRES
@;460=@

governments, once a commercial discovery of oil was made in the Leasp
Sale W35 area. The studies would be part of a national planning process
that would ultimately eliminate a proliferation of tanker traffic and
OCS-related facilities and operations, thereby minimizing threats to
navigation and harmful onshore effects. 28/

Morethan a year later, regulations governing drilling activities 'in the
shipping lanes have been proposed but not -made final.- 29/ Meanwhile, exDloratory
rigs have been drilling in shipping lanes for the past six months. Furthermore,
although commercial discoveries of oil have been made on OCS Lease Sale #35 tracts
in the San Pedro Bay, the BLM has not initiated a cooperative effort with state
and local governments to conduct the promised pipeline corridor studies.

Lease Sale #48 was scheduled by the previous Administration as part of an
ill-considered accelerated leasing*program. This program was arbitrarily formu-
lated without the benefit of a cohesive national energy policy that would enable
a rational examination of OCS development's role in meeting national energy needs.
.The new Administration indicated its intention to review the schedule in light of
this deficiency. 30/

Under the previous Administration, the Department had reduced the original
ten-million-acre-per-year leasing goal 31/, and the schedule for opening all
frontiers to leasing by 1978 was extendi-d to 1980. 32/ However, the Department
still lacks an adequate data base and sufficient staff to produce reliable resource
estimates. In addition, inadequacies in federal leasing policy and baseline
studies noted in Chapter 13 still plague the Department's OCS leasing program.
Many of these inadequacies would be corrected through enactment of currently pend-
ing legislation to amend the Outer Continental Shelf Lands Act.

CONCLUSION

Well into 1977 it was not clear to what degree the Interior Department would
respond to State and local government concerns over Lease Sale #48. Representatives
of the State met with Department of Interior officials,apoointed by the new Admin-
istration on February 28, 1977,to request -that Lease Sale #48 be postponed until:

1. the Department of the Interior fully reconsidered the National OCS
Leasing Schedule in the context of developing a national energy policy;
2. amendments to the Outer Continental Shelf Lands Act, providing additional
environmental safeguards and an enhanced role for the states in leasing
and development decisions, have been enacted;
3. California received necessary assurances that OCS leasing and development
will be conducted in a manner consistent with the State's Coastal Zone
Management Program;
4. more reliable petroleum resource and geologic data, resulting from
current southern California OCS exploration activities, became available;
5. adequate.plans for the disposition of the impending West Coast crude oil
surplus, to which additional OCS leasing and development will contribute,
have been made; and,
6. the issue of potential conflicts between OCS exploration and development
and vessel navigation has been adequately resolved.

On May 17, 1977, California and all coastal states received a clear signal from

621

Secretary of the Interior, Cecil D. Andrus, that the new Administration would be
more sensitive to state and local concerns in the OCS leasing and development
process. Secretary Andrus replaced Secretary Kleppe's OCS Leasing Schedule with
a newly-revised OCS Planning Schedule covering sales to be held through the end
of 1978. Lease Sale #48, originally scheduled by Kleppe for March, 1978, was
removed from the schedule of 1978 sales.

The Secretary also announced his intention to issue a schedule in August to
cover sales for the 1979-1980 period in which Lease Sale #48 might be included.
Describing the new schedule, Secretary Andrus said:

The principal goal of the program continues to be the increased produc-
tion of oil and gas from U.S. offshore areas ... .. Completion of develop-
ment in known areas, along with a steady exploration and development
pattern in frontier areas (including Alaska), are the twin thrusts of
the program. There remains a critical need to develop the Nation's
overall oil and gas resourices as a part of the President's National
Energy Plan.

What is substantially different is the manner in which the program will
be carried out in relation to the states, local government, and the
general public. While expecting that every region will support and
contribute to the program, I intend to recognize fully the distinct
social, economic, technological, cultural, and 'environmental elements
with each individual region and sale.

The emphasis will be on working with the states and others to resolve
key issues associated with sales or the opening of new regions. I
believe this objective can be accomplished most effectively by providing
adequate time in the planning process for resolving conflicts and
involving coastal states in a significant manner. 33/

California state officials and local governments are relieved that the new
Secretary',s assessment of Lease Sale #48 apparently resulted in conclusions simi-
lar to their own, that Lease Sale #48 was scherluled precipitously and, as
such, was destined to proceed based on inadequate environmental and oil and gas
resource information. However, no state should be required to rely on the uncer-
tainties of an OCS leasing and management policy that may change from Administration
to Administration. Nor should the petroleum industry be expected to operate in an
atmosphere of political uncertainty.

It is importan t to continue all efforts to achieve mandated reforms in the
OCS leasing and development process through enactment of the OCS Lands Act Amend-
ments. Insofar as Lease Sale #48 is concerned, the Bureau of Land Management-.'s
Pacific Coast Office will continue to prepare the Environmental Impact Statement
for OCS Lease Sale #48 using an extended schedule for completion of the draft.

California state and local governments must avail themselves of the extended
time to assure accurate and complete consideration of the effects of Lease
Sale #48 on the southern California environment. Only active and persistent
state and local government involvement will assure an Environmental Impact State-
ment suitable for informed decision making on Lease Sale #48.

622

.FOOTNOTES

1. Federal Register, July 16, 1976.

2. Letter from Bill Press, Director, Governor's Office of Planning and
Research, to George Turcott, Associate Director, Bureau of Land Management,-
September 14, 1976.

3. Letter from Santa Barbara County Board of Supervisors to George Turcott,
Associate Director, Bureau of Land Management, December 6, 1976, Resolution of
Santa Barbara City Council, September 7, 1976.

4. Letter from,Los Angeles County Supervisor James Hayes to George Turcott,,
Associate Director, Bureau of Land Management, September 3, 1976.

5. Letter from Newport Beach City Council to George Turcott, Associate
Director, Bureau of Land Management, July 28, 1976.

6. Letter from San Diego County Board of Supervisors to George Turcott,
Associate Director, Bureau of Land Management, November 16, 1976.

7. Letter from Comprehensive Planning Organization of the San Diego Region
to George Turcott, Associate Director, Bureau of Land Management, November 19, 1976.

8. Letter from Malcolm A. Love, Chairman, San Diego Coast Regional Commis-
sion to Melvin B. Lane, Chairman, California Coastal Zone Conservation Commission,
November 3, 1976.

.9. Letter from Mayor Pete Wilson, San Diego, to Secretary of Interior
Thomas Kleppe, August 6, 1976.

10. Press release, "Seventeen Companies Nominate Five Million Acres for Pro-
posed Oil and Gas Lease Sale (OCS #48) Offshore Southern Cal.ifornia," U.S. Depart-
ment of.the Interior, Bureau of Land Management, October 6, 1976.

11. Letter from William Grant, Manager, U.S. Department of the Interior,
Bureau of Land Management, Pacific OCS Office, to Suzanne Reed, OCS Project
Manager, Governor's Office of Planning and Research, November 26, 1976.

12. Letter from Suzanne Reed, OCS Project Manager, Governor's Office of
Planning and Research to William Grant, Manager, Department of the Interior,
Bureau of Land Management, Pacific Coast Office, October 25, 1976.

13. Letter from Bill Press, Director, Governor's Office of Planning and
Research, to Ronald Coleman, Assistant Secretary of Interior for Program Develop-
ment and Budget, November 15, 1976.

14. Telegram from Frank Edwards, Assistant Director, Bureau of Land Manage-
ment, to Governor Edmund G. Brown, Jr., California, January 17, 1977.

15. Letter from Bill Press, Director, Governor's Office of Planning and
Research, to Curtis J. Berklund, Director, U.S. Department of the Interior, Bureau
of Land Management, January 5, 1977.

16. Memorandum from Director, Bureau of Outdoor Recreation, to Director, U.S.
Department of the Interior, Bureau of Land Management, June 3, 1976.

623

17. Letter from Robert M. White, Administrator -National Oceanic and Atmos-
pheric Administration, to Curtis Berklund, Director: U.S. Department of the
Interior, Bureau of Land Management, June 7, 1976.

18. Memorandum from Allan Hirsch, Director, U.S. Department of the Interior,
Fish and Wildlife Service,-to Direct.or, Bureau of Land Management.- June 25, 1976.

19. Letter from John R. Twiss, Jr., Executive Director, Marine Mammal Com-
mission, to Curtis Berklund, Director, U.S. Department of the Interior, Bureau of
Land Management, September 8, 1976.

20. Letter from Rebecca Hanmer, Director, Environmental Protection Agency,
Office of Federal Activities, to Curtis J. Berklund, Director, U.S. Department of
the Interior, Bureau of Land Management, May 19, 1976.

21. Memorandum from R. Rodgers, Assistant Secretary for Fish and Wildlife
and Parks, National Park Service, to Director, Bureau of Land Management,
May 17, 1976.
22.. Press release, "Interior Makes Tract List Available for Possible Southern
California Offshore Sale (OCS #48)," U.S. Department of the Interior, Bureau of
Land Management, January 18, 1977.

23. Letter from Harold Martin, Acting Manager, U.S. Department of the
Interior, Bureau of Land.Management to Bill Press, Director, Governor's Office of
Planning and Research, February 10, 1977.

24. Letter from Arthur Letter, Director for Intergovernmental Relations,
Comprehensive Planning Organization, to Bill Grant, Manager, U.S. Department of
the Interior, Bureau of Land Management, Pacific OCS Office, March 22, 1977.

25. Letter from Bill Press, Director, Governor's Office of Planning and
Research, to Bill Grant, Manager, U.S. Department of the Interior, Bureau of
Land Management, Pacific Coast OCS Office, April 4, 1977.
26. County of San Diego, et al. v. Cecil Andrus, et al., USDC SD (No. 77-0236-
N), filed-April 14, 1977.

27. Bureau of Land Management, Final Environmental Statement: Proposed 1975
Outer Continental Shelf Oil and Gas General Lease Sale Offshore Southern California
TOCS Sale No. 35), U.S. Departme'nt of the Interior, vol. 3, p. 93.

28. Ibid., vol. 2, p. 538.

29. Secretary of the Interior, Cecil Andrus, Testimony before the House
Interior and Insular Affairs Committee, February 1, 1977.

30. U.S. General Accounting Office, op.cit., p. 59.

31. Federal Register, October 21, 1976.

32. Press release, "Revised Outer Continental Shelf Oil and Gas Planning
Schedule is Released," U.S. Department of the Interior, Bureau of Land Mana-gement,
January 12, 1977.

33. Press release, "Revised OCS Planning Schedule Announced," U.S. Department
of the Interior, Bureau of Land Management, May 17, 1977.
&76658--404 11-77 2M 624

LEGEND

SENSITIVE RESOURCES
INVENTORY

Pinniped Rookery &
Major Hauling Out Site

Marine Bird Rookery

CD Wetland

Rocky Intertidal

@R Kelp Bed

Sandy Beach

.......... Area of Special
Biological Significance

00000 State Oil, & Gas Sanctuary

------ Ecological Reserve &
Marine Life Refuge

.......... Estuarine Sanctuary

Three Mile Line

INDEX

SANTA BARBARA

VENTURA

LOS ANGELES

35
H 15 16
37

1 ORANGE

40
38 E
39
2

41 2 SAN DIEGO
2

INVENTORY MAPS
LEGEND and INDEX
(FOLD OUT)

2!0"' 3""