Oil and gas leasing of North Carolina's submerged lands

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

CA.

Oil and Gas Leasing
of
North Carolina's Submerged Lands

COASTAL ZONE
INFORMATION CENTER

Charles D. Wyman
David J. Brower
Robert M. Kessler
Center for Urban and Regional Studies
University of North Carolina at Chapel Hill

MARCH 1984

fill
North Carolina
Coastal Energy Impact Program
---------- Office of Coastal Management
--------------
North Carolina Department of Natural Resources
-----------
and Community Development

HD CEIP REPORT NO. 38
243
N8
W 7VO"-

W94
1984

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Resources and Community
Development
Box 27687
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Series Edited by James F. Smith
Cover Design by Jill Miller

OIL AND GAS LEASING OF NORTH CAROLINA'S

SUBMERGED LANDS

Charles D. Wyman
David J. Brower
Robert M. Kessler

Center for Urban and Regional Studies
University of North Carolina at Chapel Hill*

Property of CSC Library

The preparation of this report was financed through a Coastal Energy
Impact Program grant provided by the North Carolina Coastal Management
Program, through funds provided by the Coastal Zone Management Act of
1972, as amended, which is administered by the Office of Coastal Zone
Management, National Oceanic and Atmospheric Administration. This CEIP
grant was part of NOAA grant NA-83-AA-D-CZ028.

CEIP Report No. 38

March 1984

6cj U S DEPARTMENT OF COMMERCE NOAA
N COASTAL SERVICES CENTER
*108 Battle Lane, Chapel Hill, N.C. 27514 2234 SOUTH HOBSON AVENUE
CHARLESTON ; SC 29405-2413

TABLE OF CONTENTS

TITLE PAGE

List of Figures . . . . . v
List of Tables . . . . . . . . . . . . . . . . . . vi
Acknowledgements . . . . . . . - - vii

Summary of Major Recommendations . . . . . . . . ix

1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . 1

2. History of Oil and Gas Leasing and Drilling in
North Carolina's Submerged Lands . . . . . . . . . . . . . . 3

3. Legislation . . . . ... . . . . . . . . . . 11

3.1 Powers to Lease 11
3.2 Oil and Gas Activities 12
3.3 Environmental Protection . . . . . . . . . . . . 13

4. Basic Considerations . . . . ... . . . . . . . . . . . . . . . 25

4.1 Policy . . . . . . . . . . . . . . 25
4.2 Government Participation and the Allocation
of Leases . . . . . . . . . . . . . . . . . . . . . 29

5. The Pre-Sale Leasing Program . . . . . . . . . . . . . . . . 37

5.1 The Oil and Gas Lease ... . . . . . . . . . . . 37
5.2 The Leasing Process . . . . . 38
5.3 Protection of Environmental and Economic Resources . . . . . 63
5.4 Area and Rate of Leasing . . . . . . . . . . . . . . . . . . 73
5.5 Pre-Sale Exploration . . . . . . . . . . . . 88
5.6 Selection of Lessee . . . . . . . . . . . . . . . . . . . . 93

Recommendations . . . . . . . . . . . . . . . . . . . . . . 114

6. Lease Administration . . . . . . . . . . . . . . . . . . 119

Appendix A. Advisory Committees . . . . . . . . . . . . . . . .. . A-1

Appendix B. Acronyms Used in the Text . . . . . . . . . . .. . . . B-1

Appendix C. Petroleum Prospects in the Coastal Plain of
North Carolina . . . . . . . . . . . . . . . . . . . C-1
iii

TITLE PAGE

Appendix D. Environmental Impacts of Petroleum Exploration and
Development in North Carolina's Submerged Lands . . . D-1

Appendix E. Legislation, Regulation, and Permitting . . . . . . . . E-1

Appendix F. Lease Form for Oil and Gas Mining in
Submerged Lands . . . . . F-1

LIST OF FIGURES

Figure No. Caption Page

2-1 Oil and Gas Wells.in North Carolina, 1925-1983 . . . . . 4

2-2 Exploratory oil and Gas Wells Drilled in
North Carolina By Period, 1925-1983 . 0 . . . . . . . . 5

2-3 Submerged Lands Leases Issued in North Carolina,
1944-1976 . . . . . . . . . . . . . . . . . . . . . . . 6

5-1 Pre-Sale Milestones, Selected Offshore Leasing
Programs . . . . . . . . . . * . . . . . . 42

5-2 Principal Review Procedures for NRCD Actions Subject
to the North Carolina Environmental Policy Act . . . . 50

5-3 Proposed Substantive Review Procedures for Submerged
Lands Oil and Gas Lease Applications . . . . . . . . 54

5-4 Lease Tract Configuration for California's
Point Conception Sale 76

LIST OF TABLES

Table No. Title Page

3-1 Legislation Affecting Oil and Gas Activities
in Submerged Lands 15

3-2 Permits, Licenses, and Certifications for oil
and Gas Activities in Submerged Lands . . . . . . . . 19

5-1 United States Offshore Drilling and Production Data . . . 40

5-2 History and Sale Scheduling of Selected Offshore
Leasing Programs . . . . . . . . . . . . . . . . . . . . 41

5-3 Chronology of Major Events in the Review of the
. Murphy Lease Proposal * * . * . * * * . . * e . . * 44

5-4 Major Features of Review Procedures in Selected
Leasing Programs . . . . . . . 0 0 . . . 0 .I. 0 60

5-5 Suggested Timetable for Proposed Review Process
(EIS Option) . 0 0 . 0 9 0 * 0 . 0 0 0 0 . 0 . 0 0 0 . . 62

5-6 Example*s of Stipulations Attached to Offshore Oil I
and Gas Leases . . . . .67

5-7 Measures for Reducing the Impacts of Petroleum
Development in North Carolina's Submerged Lands 70

5-8 Lease Tract Size in Selected Leasing Programs . . . 74

5-9 Regulation of Petroleum Exploration by Selected
States and the Federal Government . . . . . . . . . . . 90

5-10 Requirements for Bidder Eligibility . . . . . . . . . . . 100

5-11 Bidding Systems Used by Selected Leasing
Programs, 1970-1983 o o o . . . . . o . . . . 109

ACKNOWLEDGEMENTS

The authors wish to gratefully acknowledge:

a the many people in North Carolina and elsewhere, including our two

advisory committees (Appendix A) and the leasing program staff of other

states, who took time out of their busy schedules to answer our questions,

review our plans and drafts, and offer many helpful suggestions;

* Jim Smith, the CEIP coordinator, for his advice and support throughout

the study;

Dirk Frankenberg, of the Curriculum in Marine Sciences at.the

University of North Carolina at Chapel Hill, who wrote part of Appendix D and

served as an advisor throughout the project; and

'0 Lee Mullis, Carolyn Jones, and Howard Cuppitt, of UNC-Chapel Hill, for

their excellent work in typing this report and in preparing the maps in

Chapter Two.

vii

SUMMARY OF MAJOR RECOMMENDATIONS

North Carolina General Statute �146-8 authorizes the state, upon request

of the Department of Natural Resources and Community Development, to sell or

lease mineral interests in state-owned submerged lands. Under this authority,

the state has issued seven submerged lands oil and gas leases in the coastal

area, the first in 1944 and the most recent in 1976. None resulted in any

commercial find of oil or gas, and all have since expired.

This study reviews the state's options for exercising this authority with

respect to oil and gas and presents a number of recommendations for the design

of an oil and gas leasing program. The principal recommendations are:

1. A program for the development of public oil and gas resources in

submerged lands should pursue, at a minimum, the following objectives:

(a) to develop these oil and gas resources in an orderly and timely
fashion;

(b) to provide a fair market return to the state for the disposition
of these resources;

(d) to ensure that energy development is pursued within a context of
orderly and balanced use and preservation of all coastal
resources;

(e) to minimize administrative burdens on government and industr y,
and maximize the predictability and credibility of the program;

(f) to enhance competition and economic efficiency; and

(g) to provide all sectors of government and the public at large
with timely access to the decision-making process. Pp. 25-28.

2. Any exploration and development of public oil and gas resources in

state-owned submerged lands should be undertaken by the private sector under

lease from the state. Pp. 29-31.

3. Lessees should be chosen by competitive bidding. Pp. 31-35.

4. Areas to be considered for lease should be determined primarily by

unsolicited applications from industry, though the state may consider

unnominated tracts as it deems appropriate. Pp. 45-47.

5. To help ensure that environmental resources are adequately protected

and that all legitimate concerns are identified and addressed, a three-phase

procedure is recommended for review of all appleations. First, a preliminary

review would be conducted by the Division of Land Resources to determine such

matters as the completeness of the application, the ownership of the land in

question, and the status of the offshore lease market. Upon recommendation by

Land Resources and concurrence of the Secretary, the application would then

enter the second or substantive review phase. The review would be conducted

either by the OCS Task Force or by a task force established by the Secretary

and composed of NRCD and other state personnel. Uncertainties exist regarding

future SEPA rules, but a hypothetical review procedure, assuming existing SEPA

rules and an NRCD task force, is proposed (p. 54) and would include (1) review

of the application to determine if'it is or may be.in the public interest;

(2) if so, preparation of a Draft EIS, in most cases; (3) intradepartmental

review of the Draft EIS, with changes as appropriate; (4) review of the Draft

EIS by other state agencies, federal agencies, local governments, and the

public, with one or more public hearings; and (5) after receipt of comments, a.

decision by the task force to reject the application or recommend a lease sale

to the Secretary. In the final phase, after Secretarial approval the Final

EIS and a proposed notice of sale would be prepared, the notice released for

public comment, sent to the Department of Administration, Governor, and

Council of State for approval, and finally issued as a final notice by the

Secretary. Pp. 47-59.

6. A thorough environmental analysis and review should be conducted

before the sale, not only to determine the advisability of the sale but also

to ensure that all potential impacts are satisfactorily addressed by one of

several vehicles of control available to the state, and to identify for the

benefit of the bidders the major, likely requirements and restrictions to be

imposed on lessees during the permitting stage. Pp. 63-69, 71-72.

7. Following review of each rejected application, the state should

consider whether the facts of the case warrant,promulgation of a temporary

moratorium on leasing within certain areas. P. 65.

8. The state should continue to use an extension of the OCS grid into

state waters to delineate block boundaries. The presumption should be that

the 2304-ha. blocks will be offered individually for lease, but industry

should be given the chance to demonstrate that tracts larger than a single

block are needed to provide sufficient incentive for exploration and develop-

ment. Pp. 73-77.

9. All questions of ownership interests, surface access rights, and

liability for damages in areas being considered for lease should be resolved

before leasing, if possible, and lease provisions should be used to establish

the obligations of the various parties. Pp. 77-83.

10. All companies conducting oil.and gas exploration in state waters

should be required to obtain a permit from Land Resources and to provide the

Division, upon request, with copies of survey data. The latter will require

authorizing legislation. Pp. 88-93.

11. The lease sale should be conducted by sealed bidding. The bidding

system used (the bidding variable and other, fixed terms) should be tailored

to the characteristics of the individual sale, but should involve only a

single variable and at least initially should not include profit-share

payments. Pp. 102-110.

12. The General Assembly should be requested to authorized NRCD to

promulgate rules governing oil and gas operations on state lands.

Pp. 66-69.

xii

CHAPTER ONE

Introduction

In 1937 the General Assembly approved legislation specifically authoriz
ing the state to lease state bottomlands for mineral extraction, including oil
and gas development.1 Since then, beginning in 1944, there have been a total
of seven oil and gas leases of the state's submerged lands; the last active
lease expired in 1978. Under these and other leases, over 100 exploratory
-wells-were drilled in the eastern coastal plain, including four in thewaters
of Pamlico and Albemarle Sounds. All have been dry. Yet large areas remain
unexplored, and at least some geologists feel that hydrocarbon deposits of
commercial size very possibly occur in eastern North Carolina.

Also since 1937, and particularly in the last dozen years, a growing
understanding of the environmental and economic importance of the state's
coastal resources has developed. This in turn has generated concern regarding
the possible impacts of state oil and gas leasing of submerged lands, concern
that -- was precipitated by lease applications in 1977 and 1980 and by the pro-
posed leasing of tracts near Cape Lookout in federal OCS Lease Sale 56. In
response to these events, officials in the Department of Natural Resources and
Community Development concluded that a re-examination of the state's leasing
program and procedures was needed, particularly to ensure that adequate
environmental safeguards are in place and that the state receives fair market
value for the sale of public resources. As part of this re-examination, a
study of the state's leasing procedures was undertaken by the Center for Urban
and Regional Studies at the University of North Carolina at Chapel Hill, with
funding from the Coastal Energy Impact Program. This report presents the
findings of that study.

The study has had three major objectives:

1. To review the issues surrounding leasing of submerged lands for oil
and gas development in North Carolina;

2. To provide the results of this analysis to responsible state
officials and other interested parties in a report that reviews the issues,
examines alternative approaches, and makes specific recommendations for a
leasing program; and

3. To draft regulations, as appropriate, thatwill implement the major
findings of the study.

Three sources of information were consulted in reviewing leasing issues
and in drafting recommendations. First, what relevant literature exists-was

lNorth Carolina General Statutes �146-8. See Chapter 3 for the text and
a discussion of the statute.

examined. This literature is most extensive for the federal OCS'program,
particularly -with regards to obtaining fair market value and selecting
appropriate bidding rules and methods. Second, a variety of people in North
Carolina with interest and expertise in the subject_were consulted. These in-
cluded officials in various agencies of state government, researchers at
several universities, and people representing several non-state-governmental
interests. Finally, the study drew extensively on the experiences of the
federal OCS program and leasing programs in other states. After contacting
agencies in most coastal states, it was determined that six states have active
submerged lands leasing programs: 'Alaska, California, Texas, Louisiana,
Mississippi, and Alabama. These six programs and the OCS program were
examined in depth, and their experience, together with occasional lessons from
other states, is discussed at various locations throughout the report.

The study was concerned onlywith submerged lands, i.e., those lands
lying below mean high water in the state's sounds, rivers, lakes, creeks, and
offshore waters.2 The vast majority of this submerged acreage occurs in the
coastal area, and this is also where oil and gas interest in the state has
historically been focused. For- these reasons, and because the _' water bodies of
the Piedmont and Mountains are sufficiently narrow that almost all drilling
-would be done on land, the discussion and recommendations below focus on the
coastal area.

The study only touches on the difficult question of title to submerged
lands. Literally thousands of private claims to property interests in sub-
merged lands have been registered__with the state. While the legitimacy of
these claims is obviously of direct concern to any leasing program, the issue
is too complicated to be dealt 'with here, and is being addressed by others.
For the purposes of this study, it is assumed that title of lands being
considered for lease rests with the state.

The report can be loosely organized in three main parts. Chapters 2 and
3 provide an introduction to the history and statutory environment of
submerged lands oil and gas leasing in North Carolina. The discussion of
leasing issues themselves and the study's recommendations for a leasing
program are presented in Chapters 4 through 6. During the course of the study
a substantial amount of information was assembled that, while not central to
the problem of leasing program design, helps to establish the context of the
problem or expands upon possible solutions. This material is presented in a
series of appendices.

2As a result of the Submerged Lands Act of 1953 (43 U.S.C. ��1301-1315)
and as confirmed by the Supreme Court (United States v. Maine et al., 420
U.S. 515 (1975)), the state's ownership of the seabed extends three geo-
graphical or nautical miles seaward of low mean water along the state's
oceanfront coastline.

CHAPTER TWO

History of oil and Gas Leasing and Drilling
in North Carolina's Submerged Lands

The first oil well drilled in North Carolina was drilled in 1925 by Great
Lakes Drilling Company (a local concern) on the eastern shore of Lake Ellis in
Craven County.1 Known as the Great Lakes No. 2 '_well, it-was drilled to a
depth of 2404 feet,_where drilling was stopped -when the backers became
convinced crystalline basement rocks had been reached. The-well-was dry.

Since then, 122 other oil and gas wells have been drilled in North
Carolina, 114 of them in the state's @6-county coastal zone (Figures 2-1 and
2-2). Although showings of oil or gas_were reported from several -- wells, all
but one were eventually abandoned as dry holes. (The most recent - well,
drilled during the summer of 1983 in Lee County, was still being tested at the
time of writing). Four wells have been drilled in sumberged lands: one in
eastern Albemarle Sound, and three in northern and central Pamlico Sound.

The first oil and gas leases for state-owned bottomlands were let in
1944, one to the Coastal Plains Company of Kinston, and a second to Standard
Oil Company of New Jersey. It is unclear-what happened to the Coastal Plains
lease, but no submerged lands drillingwas undertaken. Under the terms of
Standard's lease, the company-was obligated to drill at least one well -within
18 months of the signing. They eventually drilled two: one at Buxton in
1946 to a depth of 10,054 feet (the deepest yet drilled in the state; crys-
talline basement was reached at 9,853 feet bel ow sea level), and a second in
1947 in Pamlico Sound 11 miles south of Wanchese, abandoned at 6,410 feet
without reaching basement. Both -were dry. Standard subsequently pulled out
and relinquished its leases later that year.3

Since then, five other submerged lands oil and gas leases have been
issued in North Carolina. The leased acreage, key terms, and histories of
these seven leases are shown in Figure 2-3. The leases share.several charac-
teristic provisions. All were apparently negotiated individually with the
prospective lessees, and competitive bidding was not used to determine and
obtain market value. Each lease covered a very large area, commonly from

liasper L. Stuckey, North Carolina: Its Geology and Mineral Resources
(Raleigh: N.C. Dept. of Conservation and Economic Development, 1965), p. 518.
2James C. Coffey, Exploratory Oil Wells in North Carolina, 1925-1976,
Information Circular 22 (Raleigh: Geology and Mineral Resources Section,
Division of Earth Resources, N.C. Dept. of Natural and Economic Resources,
1977), and files of the Division of Land Resources.

3Stuckey, North Carolina; "Prepare to Sink Drill for oil in North
Carolina," Charlotte Observer, 29 September 1944; "Oil Prospectors Discover
Lots of Things But No Oil," Raleigh News and observer, 8 June 1947.

- - - - --- - - - - - -
T ------ r -----------
141
--%ELIZ AB ETA--,,
",*C I T Y

- - - - - - - - - - - - -

4, ROCKY
MOUNT

RALEIG
-------------
00
WASHINOITON 0 0

0
Pr 0 a
GOLOSSORO

NEW.BER
E_ Ty F A I S 0 N
FAY TEVILLE 00

CLI NTON

AM-
0 L-r ----
'OPIVILLE*
JACKS 0

0 Figure 2-1
"WILMINGTON
OIL AND GAS WELLS IN NORTH CAROLINA
TABOR CI.TY
1925-1983

FROM J. COFFEY, 1977
AND

FILES OF THE DIVISION OF LAND RESOURCES

LEGEND

10 WELLS INDIVIDUAL WELLS

Figure 2-2. Exploratory oil and Gas Wells Drilled in
North Carolina by Period, 1925-1983.

V 30

0
1925- 1930- 1935- 1940- 1945- 195G- 1955- 1960- 1965- 1970- 1975- 1980-
1929 1934 1939 1944 1949 1954 1959 1964 1969 1974 1979 1983

Time Period

Data from James C. Coffey, Exploratory Oil Wells of North Carolina, 1925-1976, Information Circular 22
(Raleigh; N.C. Division of Earth Resources, Dept. of Natural and Economic Resources, 1977), and files
of the Division of Land Resources.

several hundred thousand to over one million acres. From this area, the
lessee could select tracts (ranging from 750,000 acres in the earliest lease
to 5,760 acres in the most recent) to maintain under lease for as long as oil
or gas-was produced in paying quantities. A bonus payment was either not
required or was a nominal one dollar, and annual rentals were not required
except for acreage held until year ten under the special provisions of the
1944 and 1952 leases. In the last four leases, the lease could be extended
for a period of time (25 years in three leases and 10 years in the fourth),
,without production, if the lessee met the biennial footage drilling require-
ment. Despite these similarities, the leases also evidence a progressive
tightening of terms on the part of the state, most noticeably in the amount of
acreage that could be held by a single producing well (reduced from 750,000
acres to 5,760), in the biennial footage drilling requirement (increased from
12,000 to 20,000 feet), and in the royalty paid to the state (from 1/8 to
1/6).

The last active lease of state bottomlands expired in 1978, and none have
been issued since. In 1977, Mr. Carl Schmidt applied for a lease of 55,000

Figure 2-3. Submerged Lands Leases Issued in North Carolina, 1944-1976.

------ ----- ----------- ---------------
Date: 1944-1947

----------- Issued to: Standard Oil Company of New Jersey

Major Terms: Bonus-none; Rentals-$.10/acre on
selected acreage (see below); Royalties-12.5%;
Drilling must commence within 18 months and be
pursued continuously (with lapses of only 120
days) up to 5 years, or lessees may select up
to 75,000 acres per well drilled (750,000 acre
maximum) and hold with $.10/acre rental up to
10 years or hold with continuous drilling
operations indefinitely; if oil or gas pro-
duced, up to 750,000 acres of the area then
under lease may be held for as long as oil or
------ gas produced in paying quantities.
-_---------

I. ............. History:
Date Lease Transaction Royalty Reserved by
Lessor/Assignor
1944 Issued to Standard Oil of N.J. 12.5%

1947 Lease relinquished

------ ----- --------------
............ 1,
Date: 1944-9

-------------- --------
Issued to* Coastal Plains Company

-none; Rentals-$.10/acre on
Major Terms: Bonus
selected acreage (see below); Royalties-12.5%;
- ----------
Drilling must commence within 18 months and be
pursued continuously (with lapses of only 120
............ ....
----- - ....... days) up to 5 years, or lessee may select up
to 75,000 acres per well drilled (375,000 acre
maximum) and hold with $.10/acre rental up to
10 years or hold with continuous drilling oper-
..........
ations indefinitely; if oil or gas produced,
up to 375,000 acres of the area then under
lease may be held for as long as oil or gas
produced in paying quantities.
L

History:
Royalty Reserved by
Date Lease Transaction Lessor/Assignor
1944 Issued to Coastal Plains Co. 12.5%
? Cancelled/relinquished

Figure 2-3. Submerged Lands Leases Issued in North Carolina, 1944-1976.
(Continued)

T----- ------- --------------
Date: 1952-1953?

---------------- --------------- Issued to:. Matt H. Allen, E.R. Buchan, and Ely
J. Perry, Trustees for Coastal Plains Company

-none; Rentals-$.10/acre on
Major Terms: Bonus
------- --- ----- - -- selected acreage (see below); Royalties-12.5%;
j_'
Drilling must commence within 4 months and be
pursued continuously (with lapses of only 120
days) up to 5 years, or lessees may select up
to 75,000 acres per well drilled (375,000 acre
maximum) and hold with $.10/acre rental up to
.. ....... .... ------ 10 years or hold with co6tinuous drilling oper
ations indefinitely; if oil or gas produced, up
to 375,000 acres currently under lease may be
held for as long as oil or gas produced in
... ............ ... paying quantities.

A 1@ History:
Royalty Reserved by
Date Lease Transaction
Lessor/Assignor
1952 Issued to Matt H. Allen, E.R. 12.5%
Buchan, and Ely J. Perry
1952 Assigned to E.T. Burton, Jr. ?
1953? Expired for failure to drill

------------- ------------ ------- ---------------
Date: 1957-1977

.............. .......
i Issued to: J.E. Fitz-Patrick, of Fort Worth,
Texas

Major Terms: Bonus-$l; Rentals-none; Roval-
ties-12.5%; 12,000 feet of drilling required
..... every 2 years to renew lease, up to 25 year
maximum; if oil or gas found in commercial
quantities, tracts of 73,000 acres each may
be selected and held as long as oil or gas
produced from them in paying quantities.
. .........

History:
Royalty Reserved by
Date Lease Transaction
Lessor/Assignor
1957 Issued to J.E. Fitz-Patrick 12.5%
1958 Assigned to Coastal Plains Oil Co. 3.5%
1964 Assigned to Socony Mobil Oil Co.
1969 Assigned to Coastal Plains Oil Co.
1971 Assigned to Cities Service Co. 9% + 12.5% (up
to $1.2 million)
1977 Cancelled for failure to drill

Figure 2-3. Submerged Lands Leases Issued in.North Carolina, 1944-1976.
(Continued)

-------------
- - -- ---- - ------ ---- - --------- --- ------ - - - - -- --- - ---------
..........
Date. 1960-1962

L--------- ........ . Issued to: Roderick A. Stamey, of Houston, Tx

Major Terms: Bonus-$I; Rentals-none; Royal-
ties-12.5%; 12,000 feet of drilling required
every 2 years to renew lease, up to 25 year
maximum; if oil or gas found in commercial
quantities, tracts of 75,000 acres each may be
selected and held as long as oil or gas pro-
...... duced from them in paying quantities.

7
History:
Royalty Reserved by
Date Lease Transaction
Lessor/Assignor
1960 Issued to Roderick A. Stamey 12.5%
1961 Assigned to Atlantic Coast ?
Explorations, Inc.
1962 Expired for failure to drill

T
Datet 1966-1976

Issued to: North Carolina Oil and Gas Company
........... L..........:
-_---------

Major Terms: Bonus-$l; Rentals-none; Royal-
ties-12.5%; 20,000 feet of drilling required
every 2 years to renew lease, up to 25 year
maximum; if oil or gas found in commercial
quantities, tracts of 7,500 acres each may be
selected and held as long as oil or gas pro-
duced from them in paying quantities.

@4' - -----
History:
.. .............
Royalty Reserved by
Date Lease Transaction
Lessor/Assignor
1966 Issued to N.C. Oil and Gas Co. 12.5%

1969 Assigned to Colonial Oil and 5.0%
p@, Gas Co.

1974 65% interest assigned to F.W. Carr
of Southampton, N.Y.;
10% interest assigned to K.H.
Schmidt of San Antonio, Texas
1975 Carr assigned his 65% interest to 0.5%
Schmidt
Colonial assigned remaining 25% 0.5%
interest to Schmidt
Schmidt assigned his 100% interest 1.0%
to The Anschutz Corp.
1976 Lease superseded by new lease to
The Anschutz Corp.
8

Figure 2-3. Submerged Lands Leases Issued in North Carolina, 1944-1976.
(Continued)

------------- ------------ -- ------- ------------- ---- ------I-------
Date: 1976-1978

............... ------ ......
Issued to: The Anschutz Corp. (as consolida-
tion of existing state leases of submerged
...... lands and fast lands held by Anschutz)

--------- - ---
Major Terms: Bonus-$l; Rentals-none; Royal-
-16.67%; 20,000 feet of drilling required
............ ties
every 2 years to renew lease, up to 10 year
...... maximum, with one foot credit available for
every $10 of other exploratory work; if oil
or gas found in commercial quantities, tracts
-- ----------- >
3 miles by 3 miles (5760 acres) each may be
selected and held as long as oil or gas pro-
duced from them in commercial quantities.

...........

History:
Royalty Reserved by
Date Lease Transaction
Lessor/Assignor
1976 Issued to The Anschutz Corp. 16.67%
.... cIT, 1978 Cancelled for failure to drill

acres in the Cape Hatteras area, but the request was dropped upon the death of
,the applicant in 1978. During review of the lease proposal, however, the
state initiated several major changes in its leasing program. The federal OCS
grid, consisting of lease blocks roughly three miles square, was extended into
state waters. The state declared its intention to lease much smaller acreages
than in the past, using these lease blocks, and to eliminate the practice of
selecting areas, within the lease boundaries to be held by production. A new
lease form was drafted that, among other things, provided for delay rentals,
and limited the primary lease term to five years, '- with extension possible only
through production or continuous drilling. These changes brought the state
more in line with current industry practice.

In 1980, a request was received from Mr. Shirley Murphy to lease 35,160
acres in the Alligator iiver and Pamlico Sound and to acquire an option to
lease an additional 2,000,000 acres of submerged lands. The request was con-
sidered favorably during the early stages of review, but was deferred-when
formulation of state policy on OCS lease sales made apparent the need for a
more consistent approach to offshore leasing in state and federal waters.

CHAPTER THREE

Leaislation

State and federal laws covering a broad array of topics_will govern the
course of oil and gas development on North Carolina's submerged lands. Any
attempt to design a leasing program for North Carolina must begin-with an
understanding of what these laws permit and require.

Laws authorizing mineral leasing of state submerged lands and laws
specifically regulating oil and gas activities in North Carolina are described
below. The principal environmental protection statutes are also briefly
reviewed; more detailed descriptions of these and other applicable statutes
covering such topics as navigational rights, business and employment
practices, and historic and cultural preservation may be found in Appendix E.
Tables 3-1 and 3-2 at the end of the chapter summarize the statutes and permit
programs that will govern oil and gas development in coastal waters.

3.1 Powers to Lease

While lands under the interiorwaters of a state (e.g., Pamlico Sound)
have always been under state jurisdiction, state and federal authorities for
many years'disputed control of the lands seaward of the coastline. Congress
partly resolved the problem in 1953 with passage of the Submerged Lands Act.1
This Act revived the jurisdiction historically granted to coastal states,
determining that the zone three miles seaward of the mean low water mark is
rightfully under state, rather than federal, control. It renewed in the
states the right to "manage, administer, lease, develop, and use" these sub-
merged lands and the underlying natural resources. The Act did retain some
federal jurisdiction over matters of commerce, navigation, national defense,
and international affairs. State claims to the seabed beyond three miles-were
extinguished in 1975 by the Supreme Court in United States v. Maine.2

Disposition of interests in state-owned submerged lands is governed by
N.C.G.S. �146-3 through �146-15. These statutes forbid the sale of submerged
lands but authorize their leasing. Section 146-8 specifically gives the state
authority to sell, lease, or otherwise dispose of mineral deposits on state
submerged lands, or to lease these lands for the excavation and removal of
minerals. The full text of this section, as most recently amended in 1977,
is:

The State, acting at the request of the Department of Natural
Resources and Community Development, is fully authorized and empowered
to sell, lease, or otherwise dispose of any and all mineral deposits

143 U.S.C. ��1301-1315.

2420 U.S. 515 (1975).

belonging to the Statewhich may be found in the bottoms of any sounds,
rivers, creeks, or other waters of the State. The State, acting at the
request of the Department of Natural Resources and Community Development,
is authorized and empowered to convey or lease to such person or persons
as it may, in its discretion, determine, the right to take, dig, and
remove from such bottoms such mineral deposits found therein belonging to
the State as may be sold, leased, or otherwise disposed of to them by the
State. The State, acting at the request of the Department of Natural
Resources and Community Development, is authorized to grant to any
person, firm, or corporation, within designated boundaries for definite
periods of time, the right to such mineral deposits, or to sell, lease,
or otherwise dispose of same upon such other terms and conditions as may
be deemed wise and expedient by the State and to the best interest of the
State. Before any such sale, lease, or contract is made, it shall be
approved by the Department of Administration and by the Governor and-
Council of State.
Any sale, lease, or other disposition of such mineral deposits shall
be made subject to all rights of navigation and subject to such other
terms and conditions as may be imposed by the State.
The net proceeds derived from the sale, lease, or other disposition
of such mineral deposits shall be paid into the treasury of the State,
but the same shall be used exclusively by the Department of Natural
Resources and Community Development in paying the costs of administration
of this section and for the development and conservation of the natural
resources of the State, including any advertising program-which may be
adopted for such purpose, all of which shall be subject to the approval
of the Governor, acting by and-with the advice of the Council of State.3

3.2 oil and Gas Activities

The most important state legislation governing the conduct of oil and gas
activities is the North Carolina Oil and Gas Conservation Act.4 Part 1 of the
Act requires every driller to register with the Department of Natural
Resources and Community Development (NRCD) and file a $5000 bond to assure
satisfactory plugging of each well. Upon awell's completion or abandonment,
the operator must file with NRCD a complete log of the drilling and
development of the well.

Part 2 of the Act contains provisions for prevention of waste, estab-
lishment of drilling units, regulation of production, and notification to
NRCD prior to any drilling, abandonment, or plugging of -wells. The more
detailed regulations for drilling, casing, and plugging of -_ wells to prevent
escape, intrusion, pollution, drainage, blowouts, caving, seepage, and-well-
crowding are located at 15 NCAC 5C .0001-.0028. Also under the authority of

3The Council of State is an "executive board" consisting of all the
elected statewide officials in the Executive Branch. This group includes the
Governor, the Lieutenant Governor, the Secretary of State, the State Auditor,
the State Treasurer, the Superintendant of Public Instruction, the Attorney
General, and the Commissioners of Agriculture, Labor and Insurance.

4N.C. Gen. Stat. �113-378 to �113-415.

Part 2, the Department has promulgated rules regulating seismic exploration.5
Permits are required for all seismic work, and where wildlife will be
affected, the Secretary must consult with the North Carolina Wildlife
Resources Commission and the U.S. Fish and Wildlife Service.

For the most part, pipeline construction and operation are regulated
under state or federal law, depending on-whether the pipeline is designated as
an intrastate or interstate line. The major federal authorities are (1) the
Natural Gas Act,6_which giv`es the Federal Energy Regulatory Commission
authority to issue "certificates of public convenience and necessity" granting
a right of eminent domain for projects involving the sale or transportation of
natural gas in interstate commerce, and (2) the Natural Gas Pipeline Safety
Act of 19687 and the Hazardous Liquid Pipeline Safety Act of 1979,8 under
which authority the U.S. Department of Transportation has issued regulations
governing the design, construction, operation, and maintenance of interstate
oil and gas pi&elines. The corresponding state authority is the N.C. Public
Utilities Act; �62-110 requires certificates of public convenience and
necessity to be acquired for intrastate oil and gas lines, �62-192 confers
the power of eminent domain on these lines, and �62-50 provides for the
regulation of gas pipeline construction and operation practices, under -- which
the Public Utilities Commission has adopted the federal standards almost
verbatim.

Finally, under N.C.G.S. �143-215.100 et seq., a permit is required from
the Secretary of Natural Resources and Community Development for construction
of an oil refinery. The Secretary may deny a permit upon finding that the
facility would have substantial adverse effects on wildlife, fisheries, or a
public park, forest, or recreation area, and may require whatever measures are
necessary to prevent oil discharges.

3.3 Environmental Protection

Although there are a host of applicable environmental statutes and regu-
lationsP five statutes will provide the bulk of environmental protection for
any submerged lands considered for leasing by the state. These are:
1. The National Environmental Policy Act.10 This act requires that an
Environmental Impact Statement (EIS) be prepared for any action under federal
control and responsibility "significantly affecting the quality of the human
environment." NEPA has been held to apply to projects requiring federal

515 NCAC 5C.

615 U.S.C. ��717-71-7w.
749 U.S.C. ��1671-1686.

849 U.S.C. 5�2001-2014.

9N.C. Gen. Stat. �62-1 to �62-333.

1042 U.S.C. ��4321-4347.

permits or licenses (such as Section 10 and 404 permits, needed for
offshore drilling), but not to those merely requiring federal review of an
application.
2. The North Carolina State Environmental Policy Act (SEPA).11 A state
EIS is required under SEPA for "actions involving expenditure of public moneys
for projects and programs significantly affecting the quality of the environ-
ment of this state." Interpretations of the Act have tended to limit the
types of projects to -which SEPA is applicable; the relevance of this statute
to submerged lands oil and gas leasing is discussed in Chapter Five.

3. The Federal Water Pollution Control Act.12 Four provisions of this
Act are significant. Section 402 establishes the National Pollutant Discharge
Elimination System (NPDES), underwhich a permit (now administered by the
state's Division of Environmental Management)_ -will be required for any dis-
charges of pollutants from drilling barges, ships, or platforms. Section 401
requires that every proposed federally licensed project, including exploratory
and development drilling, be certified by the state that it will not violate
state water quality standards. Permits for the discharge of dredge and fill
materials into navigable waters are required under Section 404; this provision
is administered by the Corps of Engineers in conjunction with the Section 10
program (below), and would apply to most oil and gas activities in shallow,
estuarine waters. F@i nally, Section 311 establishes liability for oil spills
and provides for federal clean-up action, as outlined in National, Regional,
and Local Contingency Plans, should the owner or operator fail to respond
properly.
4. The Rivers and Harbors Act of 1899.13 Section 10 of this Act requires
a permit from the Corps of Engineers for any structure or other impediment to
navigation in navigable waters. Most facilities operating below the mean high
tide line, including drilling operations, storage tanks, and pipelines,will
require a permit. The Corps must consider environmental factors in its
Sections 10 and 404 permit reviews, as-well as the comments solicited from
other agencies and the public.
5. The North Carolina Coastal Area Management Act (CAMA).14 Under CAMA,
a major development permit from the Coastal Resources Commission will be
required for oil and gas drilling operations in submerged lands The stand-
ards for issuance are listed in Appendix E, and require that th; proposed
action be compatible with state guidelines for estuarine Areas of Environ-
mental Concern adopted under CAMA, approved local land use plans, general
policy guidelines for the coastal area, and the specific standards of N.C.G.S.
�113-229(e) and �113-230. Unless approval of a plan of operations is required
(see Chapter Six), the CAMA and NPDES permits will be the state's principal
instruments for environmental protection once the lease is issued.

11N.C. Gen. Stat. �10A-l to �113A-10.

1233 U.S.C. ��1251-1367.

1333 U.S.C. �403.

14N.C. Gen. Stat. �113A-100 to �113A-128.

Table 3-1

Legislation Affecting Oil and Gas Activities in Submerged Lands

Name Citation Significance

FEDERAL

Submerged Lands Act of 1953 43 U.S.C. �1301 et seq. State jurisdiction over the seabed extends
3 miles from shore

Natural Gas Pipeline Safety 49 U.S.C. �1671 et seq. Design, construction, and operation
Act standards for interstate pipelines

National Environmental 42 U.S.C. �4321 et seq. Requires environmental impact statements
Policy Act for major federal actions

Federal Water Pollution 33 U.S.C. �1251 et seq. Establishes standards and permit program
Ln Control Act for polluting discharges

Clean Air Act 42 U.S.C. �7401 et seq. Sets National Ambient Air Quality Standards
and requires permits for some emissions

Clean Water Act 33 U.S.C. �1321 Establishes liability for oil spills and
provides for federal clean-up efforts
through a National Contingency Plan
Comprehensive Environmental
Response, Compensation and 42 U.S.C. �9605 Encourages State and Local oil spill
Liability Act contingency plan(s)

Coastal Zone Management 16 U.S.C. �1451 National policy for protection of coastal
Act of 1972 areas; provides for state and local
planning and management, and consistency of
federal actions-with state programs

Endangered Species 16 U.S.C. �1531 Requires that federal action no t jeopardize
Act of 1973 listed species

Table 3-1 (Continued)

Legislation Affecting oil and Gas Activities in Submerged Lands

Name Citation Significance

Fish and Wildlife 16 U.S.C. �661 et seq. Wildlife conservation must be considered
Coordination Act in federal actions

Marine Mammal Protection Act 16 U.S.C. �1361 illegal to "take" mammals in U.S.-waters

Ports and Waterways Safety Act 33 U.S.C. 5�1221-1232 Gives Coast Guard responsibility for port
and navigational safety

Rivers and Harbors Act of 1899 33 U.S.C. �401 et seq. Regulates construction in navigable-waters

National Gas Policy Act 15 U.S.C. �3301 et seq. Sets ceiling prices for natural gas in
interstate commerce

National Historic Preservation 16 U.S.C. �470f Requires that places on or eligible for
Act of 1966 National Register of Historic Places be
considered in federal actions

STATE:

Disposition of unallocated N.C.G.S. �146-3 to Governs sale and leasing of unallocated
state lands statutes �146-15 state lands, including submerged lands

Oil and Gas Conservation Act N.C.G.S. �113-378 to Provides for regulation of oil and gas
�113-415 drilling and production in N.C.

Public Utilities Act N.C.G.S. �62-1 to Regulates intrastate oil and gas pipelines
�62-333

State Environmental Policy Act N.C.G.S. �113A-1 to Mandates preparation of State Environmental
�113A-10 impact Statements

Table 3-1 (Continued)

Legislation Affecting Oil and Gas Activities in Submerged Lands

Name Citation Significance

N.C.G.S. �143B-437 Requires impact assessment by Commerce and
NRCD of new or expanding industry

Oil Pollution and Hazardous N.C.G.S. �143-215.75 Provides for liability and state clean-up
Substances Control Act to �143-215.102 of oil spills and regulation of oil
refineries and oil terminal facilities

Water Use Act of 1967 N.C.G.S. �143-215.11 Establishes state policy for -water conser-
to �143-215.22 vation and regulatory program in capacity
use areas

Coastal Area Management Act N.C.G.S. �113A-100 Establishes state planning and management
to �.113A-128 program for coastal areas, including permits
for activities in Areas of Environmental
Concern

Sedimentation Pollution N.C.G.S. S113A-50 to Establishes erosion and sedimentation
Control Act �113A-66 control program

N.C.G.S. �76-40 Regulates placement of refuse and structures
in navigable waters under state Jurisdiction

Dredge and Fill Act N.C.G.S. 6113-229 Regulates dredge and fill activities in
state waters

Water pollution control N.C.G.S. �143-211 to Regulates discharge ofwater pollutants
statutes �143-215.9

Air pollution control N.C.G.S. �143-215.105 Regulates emission of air pollutants
statutes to �143-215.114

Table 3-1 (Continued)

Legislation Affecting Oil and Gas Activities in Submerged Lands

Name Citation Significance

Corporation Income Tax Act N.C.G.S. �105-130 to Provides state income tax deductions for
�105-130.26 health, safety, and pollution control
devices

Archives and History Act N.C.G.S. �121-.12(a) Requires that impacts on sites listed in
National Register of Historic Places be
considered before state actions are taken

N.C.G.S. �121-22 to Invests Department of Cultural Resources
�121-28 -with responsibility and -ownership of ship-
-wrecks and underwater artifacts

TABLE 3-2

Permits, Licenses, and Certifications for Oil and Gas Activities in Submerged Lands

Phases
Required
R=Required
L=Likely Admin- Statutory/
P=Possible istering Regulatory
Permit Description I II III IV Agency Authority

STATE:

Geophysical Exploration Required before R DLR N.C.G.S. �113-391;
Permit seismic exploration 15 NCAC 5C
using explosives

*CAMA Major Development For any major develop- R L L 0CM N.C.G.S. S113A-118;
Permit ment in an area of 15 NCAC 7J
environmental concern

Permit to drill explo- Required before the R L DLR N.C.G.S. �113-378;
ratory oil or gas drilling of each explo- 15 NCAC 5D
wells ratory well

*Dredge and Fill Permit For any project involv- L L 0CM N.C.G.S. �113-229;
dredging or filling in 15 NCAC 7J
estuaries

Air Quality Permit For any air contami- L L L OCM N.C.G.S. �143-215.108;
nant source with listed 15 NCAC 2D,H .0600
emission quality
standard

*Easement to Fill For filling activities P P DOA N.C.G.S. �146-6;
where land is raised I NCAC 6B .0500-0512
above high water mark

Table 3-2 (Continued)

PHASES
REQUIRED
R=Required
L=Likely Admin- Statutory/
P=Possible istering Regulatory
Permit Description I II III IV Agency Authority

Wastewater Non-Discharge For systems with over P P P DEM N.C.G.S. �143-215.1,215.3;
Permit 3,000 gallon capacity 15 NCAC 2H .0200
not discharging to
surface waters

Solid Waste Disposal For establishing and P P P DHS N.C.G.S. �130-166.18(a);
Site Permit operating disposal 10 NCAC lOG
facilities and
incenerators

0 Oil Refinery Facility For construction R DEM N.C.G.S. �143-215.100-,
Permit of refineries 15 NCAC 1F

Oil Terminal Facility For construction of R R DEM N.C.G.S. �143-215.96;
Registration any facility for
transporting, storing,
or processing oil

Water Use Permit For major uses of sur- P P DEM N.C.G.S. 5143-215.15
face and groundwater 15 NCAC 2E
in capacity use areas

Sedimentation Control For land disturbing P P L DLR N.C.G.S. 113A-54;
Plan activities on tracts 15 NCAC 4
bigger than one acre
Environmental Impact For any new or P P P P DOC/ N.C.G.S. �143B-437
Assessment expanding industry NRCD

Table 3-2 (Continued)

PHASES
REQUIRED
R=Required
L=Likely Admin- Statutory/
P=Possible istering Regulatory
Permit, Description I II III IV Agency Authority

Hazardous Waste For treatment, storage L L R DHS N.C.G.S. �130-166.18(c);
Facility Permit or disposal of certain 10 NCAC 1OF
-wastes, including mud

Tax Certification For tax reduction for P P P DHS N.C.G.S. �130-166.18(a)(3);
resource recovery, re- 10 NCAC 10C .0500
cycling, or anti-
pollution facilities

Easement over,water For any proposed P P DOA N.C.C.S. 146-12;
structures over or in 1 NCAC 6B .0600
navigable waters

State Environmental For activities using P P P N.C.G.S. 5113A-4
Impact Statement public monies and affect-
Ing the environment

Burning Permit For burning relating to P P P DFR N.C.G.S. �113-60.21 to
land clearing activities �60.31; 15 NCAC 9C .0200

Open Burning Permit For all open burning P P P DEM N.C.G.S. �143-215.3;
unless specifically 15 NCAC 2D .0520
excepted

Public Water Supply If public water supply P DHS N.C.G.S. �130-166.45;
Certification system must be expanded 10 NCAC IOD
or constructed

Water Quality Permit For systems discharging L L L DEM N.C.G.S. �143-215.1;
to surface-waters 15 NCAC 2H .0100

Table 3-2 (Continued)

PHASES
REQUIRED
R=Required
L=Likely Admin- Statutory
P=Possible istering Regulatory
Permit Description 1 11 111 IV Agency Authority

FEDERAL:

National Pollution For point source dis- L L L EPA/ 33 U.S.C. �1342; 40 CFR
Discharge Elimination charges of wastes DEM �125.122+; 15 NCAC 2H.0100
System (NPDES)

Environmental Impact For any federally li- L L L 42 U.S.C. �4332; 40 CFR
Statement (EIS) censed activity sig- �1+
nificantly affecting
the environment

Prevention of Signi- For new sources of P L L EPA/ 42 U.S.C. �7401+; 40 CFR
ficant Deterioration air pollution DEM �52.21 (b)(1)
Permit (PSD)

*�401 Water Quality For federally licensed R R. L EPA/ 33 U.S.C. �1341; 15 NCAC
Certification projects with discharges DEM 2H .0500
in state waters

*�10 Permit For any work which might R R P ACE 33 U.S.C. �401+
impede navigation

*�404 Permit For discharge of dredge L L ACE 33 U.S.C. �1344; 40 CFR
and fill materials into �235
navigable waters

Table 3-2 (Continued)

PHASES
REQUIRED
R=Required
L=Likely Admin- Statutory/
P;4ossible - istering Regulatory
Permit Description 1 11 111 IV Agency Authority

Certification of mobile To assure safety of off- L CG 46 CFR �107
offshore drilling shore drilling units
units

Coast Guard Port Ade- To assure adequacy for L L CG
quacy Certification the transfer of oil
or noxious liquid
General Pennit's of For handling LPG and P P P CG 33 CFR �126.27; 46 CFR
Handling Dangerous oil at port if tankers �154; 49 CFR �176.27
Cargo used

*Consolidated under one NRCD Application.

Phases of Activity Agency Abbreviations

1: Pre-lease DLR - N.C. Division of Land Resources (NRCD)
Il. Exploration OCM - N.C. Office of Coastal Management (NRCD)
Ill. Field Development DOA - N.C. Department of Administration
IV. Production DEM - N.C. Division of Environmental Management (NRCD)
DIIS -N.C. Division of Health Services (Department of Human Resources)
DOC - N.C. Department of Commerce
NRCD - N.C. Department of Natural Resources and Community Development
DFR - N.C. Division of Forest Resources (NRCD)
EPA - U.S. Environmental Protection Agency
ACE - U.S. Army Corps of Engineers
CG - U.S. Coast Guard

CHAPTER FOUR

Basic Considerations

4.1 Policy

Any public program, be it for the disposition of public mineral resources
or any other purpose, is guided explicitly or implicitly by a set of policies.
Which policies for the disposition of public oil and gas resources -would best
serve the interests of the people of North Carolina is a@major focus of this
report. In the next three chapters various options are considered, recommen-
dations made, and strategies for their implementation suggested. But even the
most basic decisions on the program require some policy guidance, and so
before any discussion of a program can begin, a basic policy framework needs
to be assembled or formulated.

The number and variety of policy objectives that could be used to shape
an oil and gas program are legion. Examples from other state and federal
programs and.from the literature include:

-receipt of fair market value;

-protection of the natural environment;

-protection of other human uses of state waters and submerged lands;

-protection of the socio-economic system and cultural fabric of the
coastal zone from unnecessary disruption;

-control of the rate of development to achieve various purposes,
including:
-maximization of early or overall revenues to the state;
-maximization of production over the life of the reservoir;
rapid development to lessen dependence on foreign sources and
to promote economic development;
-conservation of resources for future generations;

-control of the destination and/or price of hydrocarbons to effect
various policy objectives, including:
-aid to small businesses;
-aid to N.C. businesses;
-1-ow prices for N.C. consumers;

-increased competition;

-increased economic efficiency;

-minimal administrative burdens on government and industry;

-avoidance of unnecessary delays in exploration and development;

-maximization of North Carolina business and employment
opportunities;

-extensive local government and public participation; and

-balancing of risks and benefits among different regions of
the state.1

This list is only illustrative and could continue for pages. Some of
these policies, such as public participation, can be addressed directly in the
design of a leasing program. Others, such as environmental protection or
receipt of fair market value, cannot be achieved so directly, and the program
instead must seek to create conditions conducive to their realization. A
point to be made by the length of this list is that the state basically has a
valuable asset (oil and gas exploration and development rights) whose dispo-
sition has been authorized by the General Assembly; not only does the decision
of -whether or how to dispose of those rights involve a number of basic policy
decisions, but the opportunity to dispose of them allows the state to pursue a
number of policy objectives it may never have had the opportunity to consider
previously.

Through various processes the state has already adopted a number of
policies relevant to public oil and gas resource disposition, and.we should
look first to these for guidance. The enabling statute itself provides basic
authorization to lease but only vague policy direction:

The State . . . is authorized to grant . . . the right to such
mineral deposits, or to sell, lease, or otherwise dispose of same upon
such other terms and conditions as may be deemed -- wise and expedient by
the State and to the best interest of the State . . . .

Any sale, lease, or other disposition of such mineral deposits shall
be made subject to all rights of navigation and sub 'ject to such other
terms and conditions as may be imposed by the State.2

Similarly, N.C. General Statutes �113-8 charges the Department of Natural
Resources and Community Development to "make investigations of the natural
resources of the State, and take such measures as it may deem best suited to
promote the conservation and development of such resources." Other sources

1See, for instance, U.S. House of Representatives, Conference Report on
Outer Continental Shelf Lands Act Amendments of 1978, H. Rept. 95-1474, 95th
Cong., 2d sess., p. 92; U.S. Senate, Federal Leasing and Disposal Policies "
Hearings Before the Senate Committee on Interior and Insular Affa June 19,
1972, pp. 35-37; California State Lands Commission, Re2ort to the Legislature
on Proposed oil and Gas Lease Sale Program, Pt. Conception-Pt. Arguello, Santa
Barbara County (n.p., 1981), p. 4; Alaska Stat. �38.05.180(a); Stephen L.
McDonaD, The Leasing of Federal Lands for Fossil Fuels Production (Baltimore:
The Johns Hopkins University Press for Resources for the Future, 1979), p. 2.

2N.C. Gen. Stat. �146-8.

are more explicit. Both the North Carolina Constitution3 and the North
Carolina Environmental Policy Act4 clearly establish a state policy of
environmental protection. The Coastal Area Management Act,cites several goals
for the coastal area management system that could reasonably be applied to any
leasing program that will focus on the coastal area. Two of these goals are
"to insure that the-development or preservation of the-land and water
resources of the coastal area proceeds in a manner consistent with the
capability of the land and water for development, use, or preservation based
on ecological considerations," and, "to insure the orderly and balanced use
and preservation of our coastal resources on behalf of the people of North
Carolina and the nation.-5 The Oil and Gas Conservation Act6 declares it to
be state policy to prevent the -waste of oil and natural gas, to protect the
rights of owners of an oil or gas reservoir, and to regulate oil and gas
activities so as to protect the environment.

As a result of North Carolina's participation in the federal OCS oil and
gas program, the state, on the recommendation of the state OCS Task Force, has
adopted a number of policies on OCS development that are relevant to, and
should be compatible_with, any leasing program in state-waters. These
policies include:7 -

-the OCS program deserves support as a means of reducing the nation's
dependence on foreign sources of oil and gas;

-the program should be conducted in an environmentally responsible
manner;

-blocks -with the highest hydrocarbon potential should be offered
first;

-the risks of leasing nearshore blocks should be carefully reviewed in
the leasing decision, particularly the risk of an oil spill;

-blocks should not be leased-which represent an unacceptable level of
risk or strain on significant biological or cultural resources,
fisheriesl navigation, and other economic activities;

-cultural resources should be protected;

-local governments should be encouraged to participate in OCS
planning; and

3North Carolina Constitution, Article XIV, Section 5.

4N.C. Gen. Stat. S113A-3.

5N.C. Gen. Stat. �113A-102.

6N.C. Gen. Stat. �113-382.

7Eric Vernon, "Outer Continental Shelf Oil and Gas Leasing: Policies and
Issues for North Carolina," mimeo, Office of Marine Affairs, Raleigh, 1983,
pp. 13-19.

-environmental studies to fill information gaps should be funded and
their results used in management decisions.

The state's "balanced approach" to OCS leasing,_which supports leasing of
those tracts where oil and gas potential is greatest and restricting leasing
-where risk is greatest, led the state to object to the inclusion of nearshore
blocks in each of the three OCS lease sales held off North Carolina. Given
-what we currently know about oil and gas potential in North Carolina waters,
an extension of these OCS policies inshore.would seem toweigh against most
state leases at this time, but this is only speculation and a thorough review
of the subject will be necessary.

Finally, -_ while the state has no explicit policy requiring receipt of
fair market value in the disposition of all state property, it is certainly
implicit in many of the regulations adopted by the Department of
Administration.

Given these considerations, it is proposed that the best interest of the
state will be furthered if any program for the disposition of state oil and
gas development rights in submerged lands pursues, at a minimum, the following
basic objectives:

(1) to develop these oil and gas resources in an orderly and timely
fashion;

(2) to provide a fair market return to the state for the disposition
of these resources;

(3) to protect and enhance the natural and human environments;

(4) to ensure that energy development is pursued -_ within a context of
orderly and balanced use and preservation of all coastal
resources;

(5) to minimize administrative burdens on government and industry and
maximize the predictablity and credibility of the program;

(6) to enhance competition and economic efficiency; and

(7) to provide all sectors of government and the public at large-with
timely access to the decision-making process.

Clearly there are many additional objectives the state could pursue, and
a number of these will be mentioned in Chapter Five. Moreover the seven
listed here are not necessarily compatible, and there will be times 'when the
state will have to choose which one(s) to emphasize. All seven,we feel,
reflect the prevailing philosophy of North Carolina state government, andwill
be used to provide a framework for the design of an oil and gas leasing
program.

one of the fundamental policy decisions the state must confront early in
the design of a leasing program is the question of how aggressively the state
should promote oil and gas exploration and development. How are "orderly and
timely" to be interpreted in the first objective listed above? In the words

of Gen. Stat. �146-8, what is in "the best interest of the State?" on the one
hand, the state could approach the matter as another industrial recruitment
effort, -_ with the opportunity to provide employment and reduce the state's
dependence on imported petroleum. The state instead could take a relatively
neutral stance, with no effort to actively encourage development, but with
regulations in place to allow development provided that environmental protec-
tion and receipt of fair market value are reasonably assured. There are also
various gradations between these_two positions, but it is beyond the scope of
this report to fully explore this question. A first step in this direction
might be the preparation of a generic or programmatic Environmental Impact
Statement to help determine what is in "the best interest of the State...
Based on our research, our interpretation of the charge to us, our discussions
-with state officials, and our reading of the political climate, the latter or
neutral course appeared to us as the one the state is more likely to adopt in
the immediate future. For this reason our recommendations, particularly those
regarding the leasing process, have been developed along these lines. We
recognize, however, that there are also good arguments to be made for taking a
more aggressive approach, and have indicated at several places in Chapter Five
how the program might be altered to accommodate this approach.

4.2 Government Participation and the Allocation of Leases

Government Involvement

Ignoring, momentarily, the limitations of existing statutes, one of the
first and most obvious questions to address in considering the development of
public oil and gas resources is the extent to -which the public sector should
be involved. Should the government sell or lease exploration and development
rights to private firms and confine its activities to that of lessor and/or
regulator, or should it participate actively in the process as a financial
partner or even as field operator, through the establishment of a state-owned
oil company?

There are many models to choose among from around the world. The stand-
ard practice in the United States, at both the state and federal levels, is
for the government to lease exploration and development rights to private
firms. No active role in financial decisions is sought. There have been
suggestions from time to time that the federal government assume responsi-
bility for exploring and even developing the OCS,8 but such suggestions have
not received much support.

Dam describes several forms of government participation practiced
elsewhere.9 These include:

8See, e.g., Office of Technology Assessment, An Analysis of the
Feasibility of Separating Exploration From Production of oil and Gas on the
Outer Continental Shelf (Washington, D.C.: Office of Technology Assessment,
U.S. Congress, 1975), 290 pp.
9Kenneth W. Dam, Oil Resources: Who Gets What How? (Chicago:
University of Chicago Press, 1976), 193 pp.

1) Sole government exploration and production. In countries where
private oil firms have been nationalized, such as Mexico, the state-owned
company may conduct all exploration and development activities itself.

2) Joint venture. Joint venture operating companies may be formed by
private oil corporations and the host country (usually represented by the
national oil company) to explore and develop licensed territory. These
arrangementswere popular in the Middle East from the late 1950's through the
mid-60's.

3) Service contract. Under this arrangement, an oil company is
contracted by the host government to provide specific exploration and
development services. At least theoretically, the private firm does not obtain
any ownership interest in the natural resources themselves. Iran, Iraq and
Venezuela have used service contracts.

4) Production sharing. This arrangement combines elements of the
previous two. As used in Indonesia, the private firm serves nominally as a
contractor, being given responsibility for exploring and developing petroleum
resources 'within the contract area. Expenses are reimbursable from the oil
produced, and the remaining production is shared according to a pre-determined
formula between the company and the host country*

While the latter three arrangements may seem distinctly different on the
surface, in practice they have usually beenwritten to produce very similar
results, including little or no financial risk to the host country and
physical control of the product in the hands of the private company.

Advantages of government participation include some control over
exploration and production decisions, experience gained from working with
private companies, and the symbolism (important in many parts of the world) of
not surrendering control of natural resources to foreign corporations.
Development solely by a public entity.also allows the government to capture
both the economic rent accruing from the resource and the normal operating
profit of the operator.

There are several compelling reasons for North Carolina not to become
actively involved in petroleum exploration and development. The state
currently has no expertise and no institution to conduct such a venture. The
prospects for success in eastern North Carolina must be regarded as slight,
and any public investment in exploration would be very risky. Such
participation- would also be out-of-step with the free-market, private
enterprise philosophy that generally prevails in the state. For these
reasons, it is recommended that the state sell or lease public oil and gas
rights to the private sector.

Sell or Lease?

The statutory authorization for a leasing program (N.C.G.S. �146-8)
allows the state ". . . to sell, lease, or otherwise dispose of any and all
mineral deposits belonging to the State . . . . " There are several reasons
-why oil and gas rights should be leased rather than sold. With leases of

specific duration, the state retains some control over the timing of develop-
ment, especially to prevent acreage from being held or wells from being shut
in for speculative purposes. Furthermore, sale of mineral rights.would create
a perpetual threat to public uses of the surface. Through the lease document,
the state can also retain a fair degree of control over the lessee's conduct.
While it might be possible to overcome many of these difficulties through the
creative drafting of a deed, it could not be done 'without the deed appearing
more and more like a lease. The public trust doctrine may also preclude the
sale of these rights, despite the statute. All other states lease, rather
than sell, their mineral rights, and it is recommended that North Carolina do
likewise.

Allocation Method

If oil and gas rights are to be leased to private firms, the next
question is, how are these rights to be allocated? Ho *w should the state
choose who shall receive leases? Three basic methods have been used in other
states and countries to allocate public oil and gas rights:

1) first-come, first-served;

2) discretionary allocation; and

3) competitive bidding.

First-come, first-served. Two general approaches to allocation fall in this
category. In one, the first person or corporation to apply for a lease on a
particular tract obtains a legal right to that resource, provided certain
previously established and often quite minimal criteria are met. No negotia-
tions are involved. The best example of this system is that used for federal
onshore lands. Under the Mineral Leasing Act of 1920,10 federal onshore lands
not within any known geological structure of a producing oil and gas field and
not other-wise withdrawn from development are available for oil and gas explor-
ation and development on a first-come, first-served basis. Leases are awarded
to the first qualified applicant at established terms of 12 1/2% royalty and
$1 per acre or more annual rental. For expiring leases the chaotic situations
that resulted when applicants tried to be the first to file after a lease
expired led to the implementation of a simultaneous filing system in 1960.
Under this arrangement, all applications received within five days of the
announcement of a tract's availability are considered to have been filed
simultaneously, and the lessee is chosen by drawing. Each applicant may
submit only one application. For these leases, then,_.which account for the
majority of lease activity on federal lands, allocation is essentially by
lottery.

In the second approach, the first applicant for a lease tract does not
acquire any statutory right to the lease, and must negotiate the terms with

1030 U.S.C. ��181-287.

the public authority. Agreement may or may not be reached, but in either case
the public agency makes no attempt to identify and negotiate-with potential
competitors. This approach is followed by Canada in leasing offshore waters
that have not been previously leased,11 and has been the system in use in
North Carolina until the present.

Discretionary allocation. Discretionary allocation is the term used by Dam12
to describe those systems, in common use throughout the Yorld except the
United States, where leases or licenses are allocated among applicants
according to a set of administratively or politically derived criteria. An
excellent example is Britain's allocation of licenses in the North Sea. For
each round, applicants have been invited to submit proposals specifying work
programs, qualifications of the applicants, blocks desired, etc. Negotiations
-.with applicants regarding their work programs and other aspects of their
proposals have been common. Announced criteria used in selecting licenses
have tended to be vague; in the first round, for instance, the criteria -were
announced in the House of Commons by the Conservative minister of power as:

First, the need to encourage the most rapid and thorough explora-
tion and economical exploitation of petroleum resources on the conti-
nental shelf. Second, the requirement that the applicant for a license
shall be incorporated in the United Kingdom and the profits of the
operations shall be taxed her-e. Thirdly, in cases where the applicant
is a foreign-owned concern, how far British oil companies receive
equitable treatment in that country. Fourthly,__we shall look at the
programme of work of the applicant and also at the ability and
resources to implement it. Fifthly, we shall look at the contribution
the applicant has already made and is making towards the development of
resources of our continental shelf and the development of our fuel
economy generally.13

Criteria were altered and refined in succeeding rounds, the major change being
a new criterion that considered the extent of government participation in the
venture.

Competitive bidding. The allocation of oil and gas leases by competitive
bidding is the method of choice in the United States today. It is used by the
Federal government in allocating OCS leases, it is used by all six states
(Alaska, California, Texas, Louisiana, Mississippi, and Alabama) -_ with active
leasing programs, and it is statutorily required in ten of the sixteen states
in which the legislature has specifically provided for the leasing of sub-
merged lands.14 In this approach a leasing proposal, for a certain tract and

IlMichael Crommelin, "Offshore oil and Gas Rights: A Comparative Study,"
Natural Resources Journal 14:457-500, 1974.

12Dam, Oil Resources, p. 4.

131bid.$ p. 25.
14Alabama (Ala. Code �9-17-65), Alaska (Alaska Stat. �38.05.180f),
California (Cal. Public Resources Code �6827), Delaware (Del. Code title 7,

at specified terms, is prepared by the state, and the lease is awarded to the
highest qualified bidder in a competition that is open to all interested
parties. The bidding variable may be the bonus payment, the royalty fraction,
a percentage of net profits, or another variable.

Assessment. Each of these allocation methods has certain advantages and dis-
advantages. The main benefit of a first-come, first-served approach is that
it works efficiently.where interest is marginal and sporadic, and where there
often is no more than one firm interested in oil exploration. It--also shares
--with discretionary allocation the allowance for negotiation, which provides
the public authority with flexibility to construct a lease agreement tailored
to the individual capabilities of a firm, and permits the authority to explore
and pursue a variety of public objectives.

The main disadvantage of firs t-come, first-served systems is that they
often do not result in the state receiving full market value for the lease.
In many cases (as in North Carolina), leases have been awarded for nominal
bonus payments. Even where the size of the payment is subject to intense
negotiations, the lai:@k of competition for the lease probably results in pay-
ments of less than market value. Where preferential status is given to the
first applicant, such systems also.work to deny other companies equal access
to the resources.

.The lottery system used for federal onshore lands has been examined in a
number of studies which have identified several drawbacks to this approach.15
Over time the monetary return to the government (consisting of all the $10
nonrefundable filing fees) appears to have been less than market value, as
indicated by competitive state lease sales for comparable land nearby. A
dramatic rise in the number of filings in the.last few years has resulted in a
situation -where income from the-two methods may now be comparable.) The
lottery encourages the involvement of speculato.rs--whose sole interest is in
reassigning the lease at a profit, thus slowing the development process. In

�6128), Florida (Fla. Stat. �253.53), Georgia (Ga. Code �91.106a), Louisiana
(La. Rev. Stat. �30:126), New.York (N.Y. Envir. Conserv. Law �23-1101), Oregon
(Or. Rev. Stat. �274.765), and Texas (Tex. Nat. Res. Code Ann. title 2, sub-
chapters 32D and 52B) are required by statute to lease mineral rights com-
petively. Massachusetts, Mississippi, North Carolina, South Carolina,
Virginia, and Washington are not.
15Rocky Mountain Mineral Law Foundation, Energy Fuel Mineral Resources of
the Public Lands, Vol. III: Legal_Study of Federal Competitive and Noncom-
petitiv Oil and Gas Leasing Systems, prepared for the Public Land Law Review
Commission (Springfield, Va.: National Technical Information Service, 1970),
726 pp.; General Accounting Office, opportunity for Benefits Through Increased
Use of Competitive Bidding to Award oil and Gas Leases on Federal Lands,
Publication B-118678 (Washington, D.C.: GAO, 17 March 1979), 6 + 59 pp.;
General Accounting Office, Onshore Oil and Gas Leasing--Who Wins the-Lottery?
Publication EMD-79-41 (Washington, D.C.: GAO, 13 April 1979), 18 pp.;
General Accounting Office, Impact of Making the onshore oil and Gas Leasing
System More Competitive, Publication EMD-80-60 (Washington, D.C.: GAO, 14
March 1980), 4 + 59 pp.

some cases leases are obtained by brokers and subdivided into parcels as small
as 40 acres for assignment to speculators at a profit, making the reassembling
of tracts of sufficient size for exploration and development time consuming
and expensive. The system also invites attempts to manipulate it through
multiple filings and other means. Finally, though the lottery was instituted
as a reform and functions more efficiently and fairly than the system that
preceeded it, it also constitutes a form of gambling,__yith public resources
instead of cash awards as the prizes. While some of these problems could be
resolved by placing restrictions on who can file and on assignments, such
reforms-would result in fewer filings and less revenue.

Proponents of the discretionary system typically claim a number of
advantages over other approaches, particularly competitive bidding.16 The
ability to negotiate with individual firms has already been mentioned. A
second is that, by not requiring,large, up-front bonuses, the government does
not place a strain on the -working capital position of companies, thereby
freeing more funds for exploration. In place of bonus payments, the govern-
ment can extract agreements to pursue more extensive and aggressive explora-
tion programs, leading to faster development of resources with beneficial
effects for the economy, balance of payments, and nationii security. The
ability to award leases based on a number of criteria provides the government
--with the ability to reward admirable traits other than economic efficiency
(e.g. contributions to the local economy), to ensure a balanced mix of
companies among those awarded leases, and to use the threat of no leases in
future rounds to retain an added measure of control over firms.

ChampionsIof competitive bidding claim such advantages are illusory.17
While the flexibility to negotiate individually over the lease award is lost
in competitive bidding, the state may still negotiate collectively with
industry over the lease terms before the sale, and may also have to negotiate
a myriad of exploration and development details later during the permitting
stage. Furthermore, with some skill in drafting the government can write most
of the objectives sought through negotiation directly into the lease proposal.
If traits other than economic efficiency are to be rewarded, many of these can
be -_ written into the lease or into the eligibility criteria for bidding. With
regards to the argument that bonus payments_weaken companies financially, it
is hard to believe that any payments for North'Carolina leases will tax the
financial strength of large, multi-national oil corporations. Smaller firms
may enter the bidding through joint ventures. Moreover, advance payments are
not essential to competitive bidding; bidding may be on the royalty or net
profits percentage.

The main advantage of competitive bidding is that it establishes an
environment in which the government is more apt to obtain fair market value
for its leases. Assuming a sufficient number of bidders and no collusion,
companies will tend to bid away any above-competitive return from the
resource, leaving themselves with a normal operating profit. Since in the
long run the most efficient firms will tend to bid highest, such a system will
have the additional advantage of enhancing efficiency in the economy. By

16Dam, Oil Resources, Chapter 4.

171bid.

transferring any above-competitive return to the government, sp eculators whose
chief interest is in assigning their interest at a profit are discouraged.

Dam discusses many of these points in greater detail. However, the major
arguments outlined here are sufficient, we think, to.support our conclusion
that competitive bidding is the preferred method for allocating leases. Under
certain circumstances (e.g., when there are few bidders per tract) competitive
bidding may not function efficiently, and these situations-will be discussed
in Chapter Five.

CHAPTER FIVE

The Pre-Sale Leasing Program

In this chapter the different elements of an oil and gas leasing program
are discussed, from generation of an initial leasing proposal through execu-
tion of the lease. In addition,, the various considerations as to what to
lease and on what terms are explored. The place to begin is with an exami-
nation of the oil and gas lease itself and the rights and obligations to
which it commits the lessee and lessor.

5.1 The Oil and Gas Lease

Although a public or private landowner has the right to develop his own
oil and gas reserves, such ventures are costly and are usually left to
specialists. The most common method for delegating development authority to
these experts is the oil and gas lease. Under the lease, the developer is
given the right to explore and develop the land in exchange for a share in the
benefits of such development. The lease itself contains a set of promises and
agreements pertaining to the duration of the lease, payment for the lease, the
rights and duties of the parties, and the general conduct of the parties in
relation to each other and the land. Appendix F reviews these provisions in
detail, and a brief account of the more common terms is presented here.

The time period covered by the lease is normally divided into two parts,
called the primary and secondary terms. The primary term is an exploratory
period of definite duration, usually six months to five years, during which
the lessee agrees to undertake exploration activities in an effort to develop
producing wells. If production has not begun by the end of the primary term,
the lease will terminate, though usually there is a provision extending the
lease if continuous drilling operations are underway. The secondary term is
of indefinite duration. It goes into effect if production begins by the end
of the primary term and stays in effect so long as production continues.
Production is usually required to be "in paying quantities," meaning that
revenues must exceed operating costs. Should production stop, the lease may
usually be maintained by continuous drilling operations, but if in the
secondary term there should be no production or drilling for a specified
period, the lease automatically terminates.

As compensation for the lessee's right to enter, explore, and drill upon
the lessor's land, four types of payment may be made to the lessor. As con-
sideration for the execution of the oil and gas lease, a "bonus payment" is
typically made, representing the market value of the lease. The amount of the
bonus, which is often made on a per acre basis, may vary widely depending on
the demonstrated potential of the area, other terms of the lease, and the
potential damage or risk to other resources.

A second form of compensation is the delay rental, which is a fixed
amount paid annually during the primary term of the lease until actual drill-
ing is undertaken. Delay rental is considered a payment in exchange for the
right to delay the commencement of drilling and development operations on the
leased lands, and is usually paid on a per acre basis. Thus, during the
primary term, the lessee has a choice of drilling, paying delay rentals, or
terminating the lease and avoiding further obligations.

Once production has commenced, royalties -- the third category of
payments -- become due. Royalties represent the landowner's share of the
revenue in a joint enterprise, with the lessor providing the land and the
lessee contributing skill and capital. ordinarily, royalties are a fractional
share of the market value of production, and are paid to the lessor regardless
of the costs incurred by the lessee. When the royalties from actual pro-
duction drop below a specified minimum, the lessee is required to pay a
minimum royalty, often equal to the delay rental, which assures a reasonable
return to the lessor. Similarly, when a well capable of producing gas in pay-
ing quantities has been completed but there is no opportunity to market the
gas, a '. shut-in royalty" may be required to keep the lease alive during the
secondary term.

Finally, a relatively new type of payment known as the profit share may
be required instead of or in addition to the royalty. Under this arrangement
the lessee pays the lessor a fixed percentage of the net operating profits
from the lease, usually after some allowance has been made for recovery of
capital expenditures.

The rights and duties of the lessee are similar under all leases. in
exchange for payment of the bonus, rentals, royalties, and/or profit share,
the lessee is granted the exclusive right to drill for, extract, and produce
oil and gas within the leased area, and the nonexclusive rights to explore the
area and use the water thereon. The lessor reserves the right to grant rights
of way, geological or geophysical exploration permits, or leases for other
minerals within the leased acreage to other parties.

The duties of the lessee include the obligation, either express or
implied, to develop the land diligently. The lessee is also obligated to
drill offset wells to prevent drainage of the reservoir by other parties.
Under a pooling clause the lessee is allowed, or may be required at the
insistence of the lessor, to pool his lease acreage with that of other
lessees to form a more efficient unit that can be drained by a single well.
A unitization clause is similar, but involves the combining of much larger
acreages under a unit agreement for the efficient development of the entire
field or reservoir as a single unit.

other duties of the lessee include, among other things, obligations to
plug abandoned wells, to comply with all state and federal laws and regu-
lations, to keep accurate records, and to indemnify the lessor against
specified types of claims. Furthermore, under most leases the lessee retains
the right to reinject natural gas to repressure the formation without paying
royalties on the gas, to drill directional wells into the leased area from
other lands, to suspend operations under certain circumstances, and to sur-
render all or part of the lease at any time. In addition to the lessee's

rights and duties, the lessor (if a public agency) retains the right to issue
rules regarding well spacing, casing, and plugging, and to inspect the
operations and records of the lessee. Additional provisions of the lease
commonly govern the administration of the parties' relationship under the
lease, and deal -with such things as cancellation and default, settlement of
ambiguities in the lease, and arbitration of disputes.

5.2 The Leasing Process

Introduction

The process leading up to the competitive sale of public oil and gas
leases can be divided into four basic steps:

1) An initial leasing proposal is generated based on indications of
industry interest and input from other sources.

2) The proposal is reviewed. Information on the area is gathered, and
comments may be sought from state and federal agencies, local governments,
industry, and the public.

3) Based on these comments and information, the state decides what to
lease and on what terms.

4) The lease sale is held and leases are executed with the high bidders.

The details and timing of these steps can be organized in a number of
differentways, as can the timing of individual sales within a leasing
program. The federal government and the states provide several different
models. Tables 5-1 and 5-2 present background information on each of the
active leasing programs and their approaches to sale scheduling, and Figure
5-1 illustrates how each of the programs typically organizes the events lead-
ing up to an individual sale. Various details of these programs will be
examined throughout this chapter, but it is worth noting now the diversity
among programs. Such diversity may be traced to differences among the states
in oil and gas leasing and production history, in the economic importance of
the oil and gas industry, and in the general level of public environmental
awareness or concern.

Starting Assumptions and Considerations

There are three points that should be made at the outset of this discus-
sion of a leasing process for North Carolina. First, the reader should under-
stand that the leasing process proposed in this subchapter is based on two
important considerations: our assumption that the state does not want to
actively encourage oil and gas exploration at this time, but prefers to take a
neutral stance, and that prospects for oil and gas in North Carolina appear
meager and industry interest is currently low. Should either of these
conditions change, procedures other than the ones recommended here may be
appropriate or necessary.

Table 5-1

United States offshore Drilling and Production Data

Accumulated Offshore
Total Offshore Wells* Production to
State Waters Drilled to Jan. 1, 1980 Jan. 1, 1981

Oil Gas
(million bbls) (billion ft3)

Alaska 361 734.6 833.2

California 31,305 1,757.9 649.1

Florida 15 0 0

Louisiana 3,769@ 1,217.9 9,355.7

Texas 929 22.3 2,269.3

Washington 2 0 0

Federal Waters

Alaska 19 0 0

Pacific 418 195.3 80.2

Gulf of Mexico 16,427 5,230.1 48,451.4

Atlantic 21 0 0

*Offshore wells are defined as those located beyond natural shorelines;
-wells drilled in sounds, bays, and river mouths are not included.

Source: American Petroleum Institute, Basic Petroleum Data Book, Petroleum
Industry Statistics, Vol. 2, No. 2 (Washington, D.C.: API, 1982),
Section XI, tables 8, 9.

Table 5-2

.History and Sale Scheduling of Selected offshore Leasing Programs

Program Offshore Leasing History Sale Scheduling

U.S. Over 60 competitive lease sales 4-9 sales per year, based on
held since 1954 under Outer Con- 5-year leasing schedule, up-
tinental Shelf Lands Act; first dated periodically; intervals
sale in each region was: 1954 between sales irregular
(Gulf); 1963 (Pacific); 1976
(Alaska and Atlantic)

Alaska Except for a five year hiatus in 1-2 offshore sales per year
the late 1070's, competitive based on 5-year leasing
sales have been held regularly schedule) updated annually;
since 1959; 28 offshore sales intervals between sales
through 1982 irregular

California Long history o f competitive Sales scheduled irregularly,
offshore sales. Leasing halted based on environmental and
after 1969 Santa Barbara spill; drainage concerns and industry
first sale since then -was interest; in addition to post-
scheduled for Aug. 103, but poned sale, sale of quit-
postponed by litigation claimed tracts in Santa
Barbara channel planned.

Louisiana Long history of competitive Sales held second Wednesday of
offshore sales every month

Texas Long history of competitive Sales of Gulf lands held twice
offshore sales each year, in April and
October

Alabama Competitive sale upon request Sales scheduled irregularly de-
until major find in 1979, now pending on industry interest,
OCS process used; 1981 sale development on existing leases,
resulted in $441 million in and other factors; currently
bonuses for 13 tracts leased; one sale scheduled in 1984
smaller sale held in 1982

Mississippi Negotiated leases upon request Sales scheduled irregularly,
until 1980, now using OCS pro- depending on industry interest
cess; lease sale No. 1 (1982) and other factors; no further
resulted in $3.2 million in sales currently scheduled
bonuses for 2 tracts leased

Figure 5.1. Pre-Sale Milestones, Selected Offshore Leasing Programs

Months Before Sale 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 0 7 6 5 4 3 2 1 0

U.S. OCS

C D Area identification DED PH FED, F S
P Govs.1 comments due
Alaska
I i I --T
C D Proposed sale area mapped DED PH FED, F S
P Comments due
californial
<--Notice of preparation of
environmental document DED PH PH FED, PH P, F
(mo. 34) PH PH
Alabama

C D P PH F S
Mississippi2

C D P F S

Texas

C D F S
Louisiana

D F S

Code; C: Call for nominations/comments/information FED: Final environmental document released
D: Nominations/comments/information due Ps Proposed notice of sale or notice of intent to lease
DED: Draft environmental document released F: Final notice/advertisement of sale
PH: Public-hearing or meeting S: Sale

Note: Most milestones vary slightly in name and content among programs but have been labelled the same for ease of
comparisonj it should be kept in mind that these milestones are not exactly equivalent among programs. The
environmental document, for instance, is called an Environmental Impact Statement in the federal program, a Social,
Economic, and Environmental Analysts in Alaska, and a Program Environmental Impact Report in California, and the purpose
and contents of each are different. Some of these distinctions among programs are discussed in the text.
lCalifornia has gone through pre-sale preparation only once in the last 15 years, and this schedule illustrates the
actual sequence of events leading up to the Point Conception/Point Arguello sale that was scheduled for August 1983.
Although the sale has been postponed Indefinitely by litigation, it is shown as if it had taken place when scheduled.
2This schedule depicts the actual sequence of events leading up to Mississippi's single offshore sale, in July 1982.
The sale was originally scheduled for may, and regulations anticipate that the Notice of intent to Advertise and the
Invitation for Bids will be issued in the consecutive months preceding the sale. In this case, the sale was postponed
two months after the Notice of Intent was released while major changes were made in the sale area.

Second, the use of competitive bidding to select the lessee places
several important constraints on the leasing process employed by the state.
Among these are:

1) The information required from prospective bidders to participate in
the auction must be comparable in preparation costs, so as not to place any
bidder at a disadvantage. The amount of information required should prefer-
ably be as small as possible, so as to minimize the costs of participation.

2) Information submitted by prospective bidders may be used to qualify
bidders to participate, but may not be used to select the lessees; selection
should be based solely on monetary bids.

These two constraints have several.ramifications. The most important is
that the firm proposing a tract for leasing should not be required to submit
an environmental impact statement or proposed development plans, unless all
prospective bidders are required to do so. But the latterwould result in
duplication and waste, andwould significantly increase the costs of partici-
pation, resulting in fewer- bidders. Moreover, these documents,would not be
used to select a lessee, but at most only to qualify bidders, assuming
equitable criteria could even be established. Instead, any environmental
review document prepared before a lease sale should be the responsibility of
the state. Oil and gas technology is sufficiently standardized that the state
can predict, fairly accurately, the technology that will be used and the types
of impacts that will result, irrespective of the particular lessee. The
state may require that the costs of the document be borne by the winning
bidder, but it should not require a bidder before the sale to prepare such a
document.

Furthermore,.since the lease will be awarded before the development plans
for the lessee are known, it behooves the state to make a serious attempt to
anticipate the possible impacts of such development, and to address those that
are not covered under existing laws through lease terms and stipulations.
Several of these issues-will be expanded upon later in this chapter.

Finally, the recent experience of state government in reviewing lease
proposals is instructive in suggesting how a leasing process should be
designed. The most recent application for an oil and gas lease of submerged
landswas received in June of 1980 from Mr. Shirley Murphy. The request was
for a lease on two tracts of submerged lands totalling approximately 35,160
acres in the headwaters of the Alligator River and near Stumpy Point in
Pamlico Sound, and an 18-month option to lease approximately two million
additional acres of submerged lands north of Beaufort. A chronology of the
review of this proposal is given in Table 5-3. During the course of this
review a number of comments on procedural matters-were received from state
agencies; these comments indicated, among other things, a need or preference
in the future for:

-more information on the proposed development;

-More information on the applicant;

-opportunity for meaningful review by state agencies, local governments,
and the public;

Table 5-3

Chronology of Major Events in the Review of the Murphy Lease Proposal

Date Event

June, 1980 Lease application received

June-Dec., 1980 Application reviewed and approved by Division of Land
Resources, Earth Resources Council, NRCD Secretary, Dept. of
Administration, and Attorney General's Office, as required
by 15 NCAC 5E.

Dec. 9, 1980 Lease submitted to Governor and Council of State (COS) for
approval; COS decides more information needed, appoints
subcommittee to study proposal and make recommendations at
January meeting.

Jan. 6, 1981 COS directs NRCD to solicit public comment on proposal

Jan.-Feb., 1981 Letters sent.to chairmen of county commissioners in project
area, and notices published in several newspapers; minimal
response

March 3, 1981 COS approves lease subject to Attorney General's Office's
approval

July 23, 1981 COS rescinds approval due to inadequate review and incon-
sistencies with state OCS policies; directs NRCD to
continue investigating request with respect to environmental
protection and resource potential

late July, 1981 NRCD Asst. Sec. directs staff to (a) resolve Murphy lease
question, and (b) develop long-range procedures for
reviewing lease proposals

Sept. 5, 1981 Murphy lease proposal submitted to state clearinghouse for
distribution and review

Oct., 1981 Clearinghouse and consistency reviews completed; many
negative comments, proposal deferred indefinitely

-a full environmental analysis of the proposal;

-coordination to ensure that all potentially harmful impacts are
regulated either through lease terms.or post-lease permitting;

-review and revision (as needed) of all existing regulations governing
oil and gas development, before the lease is executed;

-policy review to ensure that lease issuance is consistent with other
state policies, particularly those dealing.with OCS issues.

A Proposed Leasing Process

The remainder of this subchapter is devoted to a discussion of how North
Carolina might organize the process by which submerged lands are considered
for leasing. The first three of the four basic steps described at the
beginning of the subchapter are dealt with here; the organization and conduct
of the sale itself is discussed in section 5.6.

Generation of the Proposal. The initial leasing proposal -- that such-
and-such an area be offered for lease -- can be generated in several different
--ways, and the experiences of the OCS and various state programs are instruc-
tive.1 All rely to a large extent on expressions of industry interest, as it
is obviously wasted effort to offer leases for-which there is no market.

lLouisiana and Texas rely almost exclusively on applications from
industry to decide what areas-.will be offered for lease. Nominations are
accepted at periodic intervals. Few applications are rejected, and only
rarely are unnominated tracts offered for lease.
Some states 'with small or nonexistent leasing programs, such as Georgia
and Virginia, also rely exclusively on applications from industry. Interest
in these states is so low that no dates for receipt of applications are set,
and each application is handled as it arrives.
The other major leasing states -- Alaska, California, Alabama, and
Mississippi -- make use of other considerations and sources of Information in
generating proposals. Typically they rely on industry and their own staffs to
determine when to schedule a sale in a particular area. Formal, confidential
nominations from industry are then solicited, and the states use these nomi-
nations together with their own geological and environmental information and
in some cases public comment to identify a proposed sale area. These programs
use far more flexibility in rejecting some nominations and adding unnominated
tracts to assemble proposed sale areas that reflect state objectives. The
U.S. once used a similar approach for its OCS program, but with the new area-
-wide lease sale concept it has moved a step closer to the Louisiana/Texas
approach of offering almost any tracts in which industry is interested.
Each of these approaches is suited for a different set of conditions,
depending on the history of oil and gas production in a state, the amount of
interest in offshore tracts, the size and diversity of the offshore area, and
the number and types of factors the statewishes to consider in making a
leasing decision.

Given the present lack of interest in North Carolina's submerged lands
and the rarity_with which applications have been received (roughly once every
2-4 years), a continuation of the former practice of taking no action until
unsolicited applications are received from industry is recommended. (Of
course, formerly the application -was an application to lease,_while now it
would be an application to offer for lease.) The advantages of this approach
are that (1.) no state effort is spent on soliciting industry interest and
preparing a sale schedule where interest doesn't exist; and (2) where there is
interest, this approach accomodates it quickly and responsively by focussing
immediate attention directly on requested tracts.

What informa tion should be submitted with the application? The area for
which a lease is sought should be specified, of course. Beyond this, the
applicant should be required to submit only information required of other
bidders, since to do otherwise would put the applicant at a competitive dis-
advantage, as discussed above. Documentation needed to qualify the applicant
as a bidder should be included, since there is no reason to accept a nomina-
tion from someone ineligible to bid. The applicant should not be requested,
though, to provide proposed development plans or an EIS. These are the
responsibility of the state, though their cost may later be charged to the
successful bidder.

Rather than require the state to begin the extensive review process for
every application, whenever received, and only for nominated tracts, there are
a couple ways to build flexibility and greater efficiency into the system.
First,-.when the state perceives an interest in submerged lands leasing
(through inquiries to the state, applications for exploration permits,
requests to review well cores, etc.), the state should be authorized to issue
a "Request for Applications," setting a single date during the following 1-2
years -when applications will be accepted, thereby allowing applications that
might trickle in over time to be considered all at once. Second, the state
should be allowed to include additional unnominated areas in the proposal for
consideration. All of the seven programs examined have this latter authority,
and the North Carolina program should possess it as-well.

Since revi ew of leasing proposals will involve a great deal of time and
effort on the part of the state and other groups, there should be some means
to discourage applications for tracts -which the companies have no serious
interests in, but which are used to obscure from competitors the real objects
of their interests. Several states have adopted filing deposits or fees for
this purpose. Alabama requires that a $25 nonrefundable filing fee accompany
every nomination. Applications in Louisiana must include a $300 deposit,
-Which is returned if the tract is not offered or if the applicant bids on the
tract, regardless of whether the bid is accepted. Texas is considering a
similar measure. It is recommended that North Carolina do the same, i.e.,
that the state require every application to be accompanied by a filing fee of
$X ($300-500?) per block, which _* will be returned if the block is either
(a) not offered, or (b) offered and the applicant bids on it, regardless of
--whether the bid is accepted. Otherwise, the deposit will be forfeited.

Finally, the identity of the applicant should be kept confidential.
Confidentiality is important in preserving competitive equality and in

providing less opportunity for collusion. Only Louisiana of the seven
programs examined publicly identifies the applicant or nominator.2

Review of the Proposal. It is suggested that the objectives of the review
process be:

-to establish avenues for incorporating all relevant information into
the decision-making process;

-to provide for the involvement of all state and federal agencies with
responsibilities related to oil and ga s exploration and development;

-to provide for the involvement of local governments and all interested
segments of the public, including the oil and gas industry, other
affected industries (e.g., fishing and tourism), environmental groups,
and concerned citizens;

-to identify before the lease is executed the major permit restrictions
that-will be imposed later; and

-to accomplish the review within a reasonable time, and,with a minimum
of paperwork and other administrative burdens.

To meet these objectives, the following review process is proposed:

(1) Pre-application contacts. These are important for advising the
potential lessee of the leasing process, the permits required for exploration
and development, the geologic information already available from previous
exploration, and other matters. There is a need throughout the leasing pro-
cess for one office to serve in a coordinating role, and this should be the
office to provide informal, pre-application consultations as well. It is
natural that the Division of Land Resources (DLR) provide both these services,
by reason of expertise and because it already serves in this capacity.

(2) Application and preliminary review. After an application is
received, several important questions can be answered relatively quickly
(within 2-3-weeks) which-will determine-whether the proposal merits further,
substantive review. These questions are:

(a) Is the application complete? Is the form filled out properly,
is the deposit attached, and has the applicant established his eligibility as
a bidder? These steps are relatively mechanical and can be easily handled by
Land Resources.

(b) Does the state in fact own the mineral rights in the nominated
area, and can they be leased? The question of existing property rights in the

2Thiswill require a statutory exception to Chapter 132 of the General
Statutes, which defines virtually all state-held documents and information as
1. public records" and requires that they be available for examination by the
public. See note 103, below.

- 47

state's submerged lands is currently being addressed by a task force of
representatives from Natrual Resources and Community Development,
Administration, and Justice (see Section 5.4). One of these agencies (State
Property office?)- would be in the best position to answer this question.

(c) What is the condition of the market for offshore leases? Is
this a good or bad time for the state to be selling? The market for offshore
leases shows cyclical patterns, and an understanding of these changes can make
a big difference in state revenues. Again, Land Resources will probably be in
the best position to judge this,with help from economists elsewhere in the
Department (Planning and Assessment?). The Secretary should make the final
decision on whether or not to defer an application because of market
conditions.

M Would issuance of a lease clearly contravene a standing policy
of the Department? Such policies will be discussed further in Section 5.3; an
example of such a policy might be a ban on oil and gas leasing in the sounds
north of Cape Lookout. Assuming the policies are easy to interpret, this is a
fairly mechanical task and can be easily handled by Land Resources.

The procedure, then, is that upon receipt an application is referred to
Land Resources. That division checks the application for completeness and for
any clear contravention of Department policy. The State Property Office is
consulted on the availability of the oil and gas rights for lease, and others
are consulted on the condition of the market for offshore leases. if none of
the answers to these questions indicate the application should be rejected or
deferred, or if the only reason for deferral is the condition of the market,
Land Resources forwards its findings to the Secretary for his concurrence.
Upon the Secretary's agreement that the application meets the above tests, the
application enters the next, or substantive, stage of review.

(3a) Statutory considerations for substantive review. In designing a
substantive review process for leasing proposals, the first step is to deter-
mine and evaluate-what relevant statutory or administrative requirements for
review already exist. There are five sets of requirements to consider,
excluding the old regulations for submerged lands leasing (15 NCAC 5E) which
the recommendations of this report are intended to replace. These are:

(a) Under the leasing statute itself (G.S. 5146-8), the Secretary
of NRCD may advise the state to execute a mineral lease,with appropriate
terms and conditions,,when he feels such a lease -would be in the state's best
interests. Any sale, lease, or contract must be approved by the Department of
Administration and by the Governor and Council of State.
M The North Carolina Environmental'Policy Act3 (SEPA) requires
that, "Any State agency shall include in every recommendation or report on
proposals for legislation and actions involving expenditure of public moneys
for projects and programs significantly affecting the quality of the environ-
ment of this Statet a detailed statement by the responsible official setting
forth the following. . . *'* State rules for SEPA were promulgated by the

3N.C. Gen. Stat. �113A-1 to �113A-10.

Department of Administration at 1 NCAC 25, and Departmental rules by NRCD at
15 NCAC 1D; the procedural requirements of these rules for NRCD actions are
shown in Figure 5-2. Unfortunately these rules lack clarity, and their
implementation has not been uniform. The state has been reviewing its
implementation of SEPA for some time, and an executive order from the Governor
clarifying responsibilities and initiating rule revision is expected soon.
Once it is issued, the Department of Administration will begin revising its
SEPA rules governing statewide implementation of the act, and other depart-
ments will follow suit.

At this time it is difficult to predict how SEPA will apply to submerged
lands leasing under the new rules. Currently there are two major questions
that the rules will hopefully answer. First, as interpreted in court cases
and opinions of the Attorney General, three conditions are needed to trigger a
SEPA-required EIS: (1)'There must be a state action, (2) public moneys must
be involved, and (3) the action must have a significant impact on the state's
environment. The leasing of state-owned submerged lands is clearly a state
action,, and in most cases we expect that there would be a determination of
significant impact. The question is: Are public moneys involved? Funds
spent on administration of an ongoing program do not qualify, so it is a
question of whether public oil and gas resources are considered "public
moneys." The existing rules are not clear on this subject. Secondly, if an
EIS is required, which agency is responsible for preparing it -- NRCD,
Administration, or the Council of State? Since the Council of State makes the
final decision on whether or not to lease, a good argument can be made that it
is their action, and not NRCD's request under �146-8, that triggers SEPA. The
Council of State, however, has never prepared an EIS or even considered which
of its actions fall under SEPA.

Even if SEPA is found not to be applicable, a strong case can be made for
using an EIS-like process anyway. The decision whether or not to permit the
oil and gas leasing of state-owned submerged lands will be one of the most
important natural resources decisions any administration will make. It is one
that the Council of State and various state agencies have emphasized should
have the benefit of state agency, local government, and public input. More-
over, with respect to the OCS program the state has consistently supported a
process that encourages open and knowledgable discussion of the risks and
benefits of oil and gas development and that allows meaningful input from
states, local governments, and the public. Such goals can best be achieved by
producing an EIS and giving it wide exposure for comment. Authorization for
preparing an EIS-like document would seem to be implicit in the requirement of
G.S. �146-8 that leasing be on such "terms and conditions as may be . . . to
the best interest of the State." Procedures for prearing such a document
could be written into the leasing rules.

(c) Executive Order No. 15 of Governor Hunt requires, among other
things, that the use and disposition of state-owned lands be consistent to the
maximum extent possible with the coastal management program, including state
guidelines and local land use plans. Consistency determinations are made by
the Office of Coastal Management (OCM). For projects that require an EIS or
negative declaration, standard procedure is for OCM first to examine the
comments generated by the clearinghouse review, then discuss any difficulties
OCM has on the project with the sponsoring agency, and then find that the

Figure 5-2. Principal Review Procedures for NRCD Actions Subject to
the North Carolina Environmental Policy Act

NRCD division proposes action subject to review under SEPA;
is action "likely to have a significant effect on the
environment of the state?"

yes maybe no

Draft EIS prepared, after Environmental Negative declaration
consultation with other state questionnaire prepared prepared
and federal agencies I
I State clearinghouse no
Document distributed by distributes Document approved by
Secretary NRCD for review Secretary NRCD?
days), comments to Review (15 working days) I
within dept. (2 .8 calendar 1 YY
I I yes I State c inghouse
Secretary NnCD and pZ:dp:r!Tg State clearinghouse distributes
division; changes recommends either
necessary; are,changes major? negative declaration
or EIS be prepared Review (15 working days)
no

St use State clearinghouse
distributes reviews comments, forwards
I comments to
Review (15 working days) I
NRCD, with or without
Dept. Admin. recommendation
State clearinghouse forwards to prepare an EIS
comments to
I
Secretary NRCD and division;
decision made whether to

Prepare Final EIS Abandon project

proved by
Secretary NRCD?

State clearinghouse
distirbutes

Source: 1 NCAC 25 and 15 NCAC 1D; procedures for appeal of agency decisions (1 NCAC 25 .0106) are not
illustrated.
S

proposal is either consistent, consistent-with conditions, or not consistent
-with the coastal management program.

(d) N.C. Gen. Stat. �143-341(4)(f) reserves a major role for the
Department of Administration in any lease transaction. This provision gives
Administration,_with approval of the Governor and Council of State, the power
and duty to make all leases of state lands, although the Governor and Council
may exempt certain classes of transactions from this requirement. However,
NRCD currently cannot seek exemption since the leasing statute itself,
G.S. �146-8, specifically requires Department of Administration approval.
While it is apparent in �146-8 that NRCD is intended to have major review
responsibilities, Administration also has a statutory duty to review and
approve any lease proposal. What is needed, then, is a means for coordinating
or combining these reviews to prevent duplication and to reach decisions
satisfactory to both departments.

(e) Several public agencies independent of the Governor have the
ability to deny necessary permits.to oil and gas lessees or in other.ways to
prohibit development. These include several federal agencies (particularly
the Army Corps of Engineers), the Environmental Management Commission, the
Coastal Resources Commission, and the county or counties in 'which the lease
blocks occur. There is a possibility that the state, having decided that
leasing 'would be in its best interests, could lease an area only to be -
frustrated in its attempts to develop it through permit denials to the lessee.
Short of statutory change, the authority of these bodies to prohibit oil and
gas development cannot be removed. It behooves the state, therefore, to
provide these bodies *with every opportunity for review of the leasing proposal
and to work with them to fashion a proposal acceptable to all parties.

The role of the Environmental Management Commission stems from its
authority to issue or review water (and possibly air) quality permits needed
by offshore oil and gas operations. The standards for these permits are
fairly specific, though, and most bidders should be able to estimate whether
such permits can be obtained and the costs of compliance with permit
conditions. The same is not true of the CAMA major permit (and to a lesser
extent, the dredge and fill permit) that must be obtained from the Coastal
Resources Commission (CRC). CAMA permit standards listed in Gen.
Stat. �113A-120 are rather vague, with much room for interpretation,
particularly regarding an activity such as oil and gas exploration forwhich
no precedents under CAMA and no specific use standards exist. What is needed
and recommended to give credence and predictability to the leasing process is
for NRCD (a) to ask the CRC to examine the question of submerged lands oil and
gas development and to prepare state guidelines under which such development
-would be permissable, and (b) to consult the CRC during normal pre-sale
reviews and make a special effort to allay its objections and concerns.

During the 1983 session, the General Assembly passed HB 865,4 which amends
the grant of zoning authority to counties i@ G.S. �143-340 by extending it to
include the estuarine waters within the counties' boundaries. 'All inshore
,waters (those landward of the barrier islands) are affected, but not those in
the three-mile contiguous zone seaward of the islands. The effects of the

41983 N.C. Session Laws, Ch. 441.

am endment must be read in conjunction with CAMA. The amendment enables a
county to impose limitations on submerged lands oil and gas development by
means of a zoning ordinance. Such an ordinance would require the county's
land use plan to be amended to include such limitations, as Gen. Stat. �113A-
111 requires that local ordinances and the land use plan be consistent with
each other-within areas of environmental concern. Since local land use plans
are incorporated into the state's coastal management program and compliance
.--with them is required before a permit can be issued under G.S. �113A-120, such
a limitation -would have the effect of requiring the CRC to deny any CAMA
permit for oil and gas development within that county's estuarine boundaries
as well.

Since a county can amend its land use plan on 90 days notice, there is
the potential that a county could frustrate the purpose of a sale long after
the sale is held and well into the lessee's planning activities. There are
three ways in which such difficulties can be avoided. First, the statutory
grant of authority to counties could be amended to exclude a class of actions
including oil and gas development in estuarine-waters. Second, since CAMA
requires that local ordinances covering areas of environmental concern be
consistent with local land use plans and that the latter be consistent with
state guidelines adopted by the CRC, then if the CRC adopted guidelines set-
ting specific conditions under which oil and gas development would be
approved, any limitations under county zoning authority would necessarily not
be in conflict with the state guidelines. Finally, the county or counties
affected could be closely involved in pre-sale planning, in the hopes that, if
all their objections could be met in the design of the lease sale, they would
not subsequently prohibit development through a zoning ordinance. The-latter
course should be followed in any case, but since it has substantial risk it is
recommended that the second option also be pursued.

All of the statutes discussed above have requirements or suggest pro-
cedures for substantive review that are compatible with the objectives of the
review process discussed earlier and that to a large extent fulfill them.
Assuming the uncertainties regarding SEPA are resolved in favor of its appli-
cation to submerged lands leasing, it is recommended that these existing
procedures be followed, with a few minor alterations, rather than new pro-
cedures be designed specifically for this program.

(3b) Procedures for Substantive review. A major preliminary step in
establishing a review process is to determine who shall be responsible for
conducting the review. One office or group is needed to coordinate the
review, to prepare or at least oversee preparation of the environmental
document, to review comments, and to make recommendations to the Secretary.
It would also be useful if this office or group included people knowledgeable
on permit requirements and conditions who could coordinate permit review and
lease administration after issuance of the lease. options include: (1) the
Division of Land Resources with advice as needed from other NRCD divisions and
state agencies, (2) the OCS' Task Force,, and (3) a specially designated task
force orworking group of NRCD and other agency personnel, chaired by Land
Resources. (The Earth Resources Council constituted a fourth option until it

--was abolished by the General Assembly in July of 1983.5) Of these, the first
option is not recommended. Expertise will be required in many different
environmental fields, and a great deal of discussion and coordination will be
needed to ensure that the full array of potential environmental problems have
been satisfactorily addressed. Recommendations to the Secretary on such a
complex issue would better be generated by consensus among the agencies most
involved, rather than by a single division such as Land Resources.

The latter two options both have much to recommend them. The OCS Task
Force is an interdepartmental group.with a proven track record and a substan-
tial amount of expertise in offshore oil and gas development. It includes
representatives of a number of different state agencies, as -well as represen-
tatives of local governments, and is chaired and staffed by the office of
Marine Affairs in the Department of Administration.6 This arrangement facili-
tates use of the Task Force as an open, neutral forum for discussion between
development and conservation minded interests. Advice would be generated not
only for the Secretary of NRCD, but also for Administration and other state
agencies and for the Governor and Council of State. A more narrowly defined
and specially constituted task force within NRCD, on the other hand,- would
arguably be more responsive to the Secretary of NRCD and his statutory
responsibilities. It could be constituted to reflect the specific interests
involved in any single sale, and could include some of the representatives
currently on the OCS Task Force (thus drawing on their expertise) as well as
representatives of agencies not currently on the Task Force but @Ith major
interests in submerged lands leasing, such as Wildlife Resources and the State
Property Office. No recommendation is offered on.which of these-two options
should be chosen.

Due to uncertainties regarding future implementation of SEPA and regard-
ing who will coordinate review of leasing proposals, we cannot recommend a
specific procedure for substantive review at this time for incorporation into
administrative rules. To illustrate what such a process might look like,
however,, we have, for the sake of argument, developed a review process based
on existing SEPA rules, assuming SEPA is applicable and that NRCD is the
sponsoring agency, and that a working group would be appointed by the
Secretary of NRCD to coordinate review. Given these assumptions, the follow-
ing procedures for substantive review are recommended (Figure 5-3; keep in
mind that any change in assumptionswill require appropriate modifications in
these procedures):

51983 N.C. Session Laws, Ch. 667.
6The* OCS Task Force is chaired by the OCS Coordinator in the office of
Marine Affairs and includes representatives of the Division of Land Resources
(NRCD), Office of Coastal Management (NRCD), Natural Resources Planning and
Assessment (NRCD), Division of Environmental Management (NRCD), Division of
Marine Fisheries (NRCD), State Ports Authority (Commerce), Office of Indus-
trial Development (Commerce), Energy Division (Commerce), Underwater Archae-
ology Unit (Cultural Affairs), Department of Transportation, Association of
County Commissioners, and N.C. League of Municipalities.

Figure 5-3. Proposed Substantive Review Procedures for Submerged Lands Oil
and Gas Lease Applications.

Secretary NRCD approves application for substantive review,
appoints task force to conduct review
I
Task force reviews proposal, consults with state and federal
personnel and others as appropriate, decides either to

conduct full-scale review under SEPA; reject application as clearly
task force decides whether not in public interest

leasing will have a leasing may have a leasing will not have a
"significant effect on the Itsignificant effect" "significant effect"
environment of the state" [unlikely]

Draft EIS prepared, after consultation environmental questionnaire negative c claration
with state and federal officials and repared and distributed, prepared
others as appropriate "'@and on basis of result',@,
I either
NR al review 1 review

State clearinghouse distributes NRCD distributes to federal
to state agencies, regional COGs, agencies, various public and
local governmients; public notice private groups

Review (60 calendar days for Draft EIS, less for
negative declaration); public hearing(s)
I
Comments forwarded by clearinghouse or sent directly to

Task force for recommendation that Office of Coastal Management for
Secretary either reject proposal consistency determination, made
or proceed with the sale in consultation with task force

Secretary NRCD decides either to reject
proposal or to proceed with the sale

The Secretary, upon approval of an application for substantive review,
appoints a working group and refers the application to it. This group meets
and, in accordance with Departmental SEPA rules, consults informally with
other state and federal personnel and may consult with local governments,
industry, environmental groups, and others as appropriate. Scoping meetings
may be held. The result will be one of two decisions:

(a) Recommendation to the Secretary that the application be rejected, on
the grounds that granting of the-lease would clearly be not in the public
interest, or that development of the lease-would result in an unavoidable
statutory violation.

.(b) Determination that the application merits further review, based on
the decision either that the lease would be clearly in the public interest, or
that it is unclear-what the public interest requires. In this latter case,
since the issue is so complex and the statutory criterion of "public interest"
so vague,, it is advisable to enter the EIS process and allow a full review so
that all sides of the issue can be fully aired, even though the task force has
not yet elected to support the proposal. The task force must then decide
among three further alternatives:

(bl) Leasing will not have a "significant effect on the environment
of the state." A negative declaration is prepared and recommended to the
Secretary. To permit a meaningful review, the declaration should contain, at
a minimum, a description of the area to be leased, proposed lease terms and
stipulations, a brief description of possible oil and gag activities under the
lease (with references to more detailed information), a summary of environ-
mental considerations,,and a description of permits and regulations that will
apply to lease activities.7 If the Secretary concurs with the negative
declaration,, it is then sent to the state clearinghouse for distribution and
review in accordance with 1 NCAC 25 .0206. However, it is difficult to
believe that a negat .ive declaration could be issued for any leasing proposal
in the foreseeable future, and negative declarations will not be discussed
further here. The procedures for their review are considered adequate, though
-with the same reservations that apply to EIS review procedures, discussed
below.

(b2) Leasing may have a significant effect. In this case an
environmental questionnaire is distributed pursuant to 1 NCAC 25 .0203. Upon
its completion, the working group must decide between (bl) and (b3).

(b3) Leasing will have a "significant effect on the environment of
the state." An environmental impact statement is then prepared,_With proposed
lease terms and stipulations, and sent to the Secretary as required by
departmental rules. The draft EIS is circulated within the Department for at
least 28 days, comments are reviewed, changes made as necessary, and the draft
statement, with Secretarial approval, is submitted to the state clearinghouse.

State regulations give preparing agencies the authority to charge the
project or sponsoring agency the cost of EIS preparation.8 These costs should

7See 1 NCAC 25 .0202 for other requirements.

81 NCAC 25 .0205-`
55

not be charged to the applicant, but could be charged to the successful
bidders; this was to be done in the Point Conception sale in California. Such
action really has only public relations value, as the amount charged only
lowers each bid by an equal amount.

In reviews of the Murphy lease, a common complaint was that the proposal
did not provide sufficient detail about proposed exploration and development
activities. With competitive bidding, this lack of detail will be common.
The EIS authors can offer likely development scenarios, but reviewers will not
have specific plans on which to comment, and should be prepared for this
difference between a lease sale proposal and most development proposals they
review.9 Opportunities for review of detailed plans will come at the
permitting stage.

Currently, standard procedure*is that upon submission of an EIS to the
state clearinghouse, copies are distributed to appropriate state agencies and
affected regional councils of government, who forward copies on to local
governments in the project area. Notice of the document's availability is
also printed in the Environmental Bulletin. Regulations require that
comments be returned.within 15-.working days (3--weeks) of when the document.was

9The Commonwealth of Virginia, in its recently adopted state minerals
Management Plan, has taken a somewhat novel approach to the review process
that has several points to recommend it. For any competitive sale of state
oil and gas rights, the major environmental review is conducted between the
lease sale and award of the lease, during which detailed plans of't'he high
bidder are subject to scrutiny. When an application is first received, it is
reviewed -within state government, lease terms and stipulations are formulated,
and the lease sale is held. The high bidder is then given six months to
submit to the state's Council on the Environment an EIS addressing the
detailed plans of the bidder. This EIS is reviewed by state agencies, local
governments, and the public afterwhich the Council determines whether the
proposed activity is acceptable and what additional restrictions, deletions,
and/or mitigating measures must be incorporated into the lease or permits.
The great advantage of this approach is that the environmental review that
is conducted before the lease is executed and the state committed can be done
on a very detailed proposal and -with the identity of the proposed lessee
known. Lease stipulations and conditions can be far more detailed and better
tailored to the proposed activities than they ever could be under an OCS-like
system. However, there are major disadvantages as well. There -will be sub-
stantial uncertainty before the sale as to the cost of the additional
restrictions imposed in the second review phase, leading to lower bids. In
addition, the successful bidder must bear the costs of EIS preparation (and
state sale costs in the Virginia system) even if the lease is not - awarded,
-which may scare bidders away, particularly small firms.who cannot risk such
costs.
it is felt that the disadvantages of this approach outweigh the advantages.
Under the process outlined in the text,with proper planning the state should
be able to attach sufficient safeguards to the lease so as to achieve, in
combination with post-sale permitting requirements, most of the environmental
protection afforded by the Virginia system,.while obtaining more extensive
pre-sale exploration, more competition, and higher government revenues.

first submitted for public review. Comments received are forwarded to the
sponsoring agency, in this case NRCD.

For review of an oil and gas leasing proposal, standard clearinghouse
review procedures are deficient in four respects:

(a) Clearinghouse review does not include federal agencies. Since
several federal agencies will be intimately involved in post-sale development
decisions, it is essential that their comments be solicited at this stage and
potential problems resolved. Review copies should be sent directly by NRCD.
The mailing list should include, among others, the U.S. Fish and Wildlife
Service, National Marine Fisheries Service, Coast Guard, Department of Defense
(including both the Corps of Engineers and services with land or facilities
nearby), and, depending on location, the National Park Service, U.S. Forest
Service, and Minerals Management Service. In light of counties' regulatory
authority mentioned earlier, copies should be sent directly to affected
counties as well.

(b) The 15-working day time 1 imit on EIS review is not sufficient for
such a complex issue. The clearinghouse regularly negotiates longer review
periods with the sponsoring agency. For South Atlantic OCS Sale 78 in July of
1983, North Carolina requested that the review period for the draft EIS be
extended from 45 to 60 calendar days. This latter figure seems appropriate
for a state EIS on leasing as well.

(c) Public notice through the Environmental Bulletin is not sufficient.
The Bulletin simply does not provide adequate public exposure. Announcement
of the leasing proposal and draft EIS availability should also be published by
NRCD in one or more local papers in the project area and in.the Raleigh News
and observer. Non-governmental organizations, such as environmental groups,
chambers of commerce, and appropriate industrial or trade associations (e.g.,
N.C. Petroleum Council, N.C. Fisheries Association) should be contacted by
NRCD and sent copies individually.

(d) one or more public hearings should be held in the project are a,, and
possibly in Raleigh as well. Public hearings are optional under SEPA regula-
tions but should be standard for oil and gas lease sale proposals.

It might also be appropriate for the state to publish notices in oil and
gas trade journals announcing availability of the draft EIS and inviting
comment. These would also serve to alert industry to the possibility that
leases may soon be issued in North Carolina waters.

Upon receipt and review of these comments by the working group, a recom-
mendation is made to the Secretary either to proceed with the project and
prepare a final EIS and notice of sale, or to reject the proposal. At the
same time, the Office of Coastal Management is reviewing the comments and its
own coastal management plan (state guidelines and local land use plans) to
make a consistency determination, which may involve negotiation with other
members of the working group.

Secretarial Decision and Notice of Sale. Based on the results of this review
and any task force recommendations, the Secretary must decide-whether to
approve the lease sale and on what terms. on what grounds should the decision
be made? G.S. �146-8 requires only that disposition be "subject to all rights
of navigation" and that it "be deemed -wise and expedient by the State and to
the best interest of the State." In other leasing programs the authorizing
statutes and regulations provide administrators with no more guidance. Most
leasing legislation establishes some program objectives or policy, but
explicit decision criteria are either completely lacking or amount to the
requirement that leasing be on such terms as are "in the best interests of the
state" (Alaska) or are "just and proper" (Mississippi).

For the sake of the public, the state employees involved in the review,
and the Secretary, it may be helpful to at least make explicit what factors
should be considered in the decision,.without making any attempt to specify
how.weights should be assigned or what levels of risk are justified. It is
recommended that program rules state that the Secretary, in making a decision,
-will consider among other things the effect of such lease(s) on:

-the quality of the natural environment, including air, surface, and
'groundwaters, and'terrestrial and aquatic life;

-cultural resources;

-recreational resources and activities;

-commercial fishing, tourism, and other industries at risk;

-navigation, shipping, and other transportation;

-socio-economic conditions in the project area, including the industrial
base, employment, housing, and the supply and use of public services;

-the potential for discovery of commercial quantities of oil or gas;

-energy supplies, the balance of payments, and national security; and

-the state treasury and the natural resource conservation and development
projects that might be funded with sale proceeds.

If the Secretary determines a lease sale to be in the public interest, a
final EIS and a proposed notice of sale are prepared. The notice of sale
serves to notify all interested parties of the Secretary's decision as to-what
will be offered and on what terms, and provides information to bidders on how
to submit bids. The notice should contain, at a minimum, a description of the
areas to be offered, a summary of the lease terms-(.with copies of the lease
available upon request), the stipulations to be attached, and information on
bidder eligibility, the bidding variable, minimum acceptable bids (if any),
the date of sale) where and how bids should be submitted, and conduct of the
sale. Several states (Texas, Mississippi, Alabama, and Alaska) also use the
notice of sale to notify bidders of limitations that may or will be imposed on
development during the permitting stage. It is strongly advised that North
Carolina do likewise, for reasons of both fairness and, by reducing
uncertainty of regulatory costs, higher bids, at lease in the long run.

In Alaska the decision-maker (Director of the Division of Minerals and
Energy Management) also issues a document known as the Preliminary Analysis of
the Director. Totaling 40-50 pages of text, it sets out the.findings of the
division with regards to the potential effects of the sale and the mitigating
measures needed to limit these effects to acceptable levels, and specifically
addresses the question of whether the sale is in the state's best interests *
In part, this is necessary because the Alaskan environmental document does not
represent the thinking of the sponsoring agency, as it does in other programs.
But in the interests of public understanding and open government, it might be
useful if the North Carolina notice of sale 'were also prefaced by a short
(2-5 page?) but specific explanation of why the Secretary decided as he did.
Such a statement could preface the final EIS instead.

Since under G.S . �146-8 the Department of Administration and the Governor
and Council of State must approve any lease, and since with competitive
bidding the terms must be finalized before the lease salei, the notice of sale
at this point should be sent to these officials for their approval. If the
State Property Office has been included in the deliberations, if the Depart-
ment of Justice has been consulted or relied upon for lease preparation, and
if state agencies and other groups have been duly consulted, it is unlikely
that any major objections-will arise at this stage.

Several programs permit additional review and comment on the proposed
notice of sale. Alaska and California provide for a period of public comment
on the notice.-while the OCS program accepts comments only from state gover-
nors and, through them, affected local governments. In Texas, Louisiana,
Alabama, and Mississippi there is no provision for review of the sale notice.
The advantage of such a comment period is that it gives the public the oppor-
tunity to comment on exactly how the Secretary weighed various considerations
and interpreted "the best interest of the State" in reaching a decision. It
gives the Department a chance to test its decision before becoming committed,
and it hopefully strengthens the impression that decision-makers have been
accessible and considerate of all comments. The disadvantages are that it
lengthens the review process and often results only in a reiteration of points
previously made.

It is recommended that the state permit public comment on the proposed
notice of sale, and that it be sent out for review via a mailing list devel-
oped during review of the draft EIS. Department of Administration and Council
of State review would then follow. After their approval, the Secretary would
issue the final notice of sale and invitation to bid. Notice should be
published not only in North Carolina but also in journals and newspapers more
visible to the oil and gas industry, as extensive advertising can only benefit
the state at this stage.

it may be of interest to note some of the major features of review
procedures in other programs (Table 5-4, Figure 5-1). The attitudes of
Louisiana and Texas with regards to their limited pre-sale review are that
extensive review is best left to the permitting stage. Such attitudes may be
justified by the long history, familiarity, and acceptance-which the oil and
gas industry enjoys in these states.

Table 5-4

Major Features of Review Procedures in Selected Leasing Programs

Review by other
state and federal Public Public Environmental
agencies? review? hearing? document?

Alabama X X X

Alaska X X X X

California X X X X

Louisiana

Mississippi X X X

Texas X

U.S. X X X X

Appeals. one of the rules for submerged lands leasing adopted in 1976
entitled a rejected applicant to a departmental hearing under 15 NCAC IB
.0200.10 The question of appeal rights under the new procedures described
above has not yet been addressed.

Rule 15 NCAC 1B .0202 ("Availability of Contested Case Hearing") states
that: "The agency shall commence a contested case hearing procedure if any of
the following occurs: ... (3) A partywho has exhausted or waived any available
prehearing processes requests a contested case hearing after the agency has,
in any matter other than rulemaking or a declaratory ruling proceeding: (A)
issued a complaint, citation, response to an application or request, or other
preliminary determination. . . ." While this language appears to entitle a
rejected applicant to a hearing, it is argued that this requirement is not or
should not be relevant. The "application or request" referred to is assumed
to be an application or request to conduct regulated activities on private
property,where denial results in a limitation of private property rights. In
regards to leasing, it is public property at stake, and the government is no
more accountable to the applicant for its decision than it is to any other
interested party. To grant all parties appeal rights would be to virtually
ensure that every leasing decision -would be followed by a hearing. Further-
more, once the application reaches the EIS stage with clearinghouse review and
public hearings, there is ample opportunity for all interested parties to be
heard. Before this point an applicant may be turned down without an oppor-
tunity to be heard, and if this is the case, a request for a hearing would

1015 NCAC 5E .0005.

have some merit. No other leasing program entitles the aggrieved applicant to
challenge the final decision. It is recommended that in North Carolina a
contested case hearing on the Secretary's leasing decision be granted at the
discretion of the Department.

Timing. A reliable timetable for review is important for instilling
confidence in the process, for ensuring that all tasks are coordinated
properly, and for protecting the interests of all parties. Most states
establish schedules of events for individual sales. Some of these are highly
elaborate; a typical in-house sale process timeline used in Alaska lists 94
separate events over a four-year span. Typical schedules for sale milestones
in the various leasing programs are shown in Figure 5-1.

It is recommended that, at the time Land Resources forwards the appli-
cation to the Secretary for his approval of further review, the Division also
submit a proposed review timetable for the Secretary's approval. A reasonable
time-frame for the review process is suggested in Table 5-5.

How long after the final notice is issued should the sale date be set?
Figure 5-1 shows that in six of the seven programs examined, the final notice
is issued 1-2 months before the sale. Most programs.require a minimum notice
of 30-60 days. Notice for the Point Conception sale in California was issued
seven months before the sale was to be held to give both the State Lands
Commission and the companies time to prepare. Virginia's new procedures and a
proposed revision of Delaware's leasing statutues would both allow up to 18
months between the final notice and the sale.11

Before a sale, companies must have time to plan and conduct geophysical
surveys (or buy them "off the shelf"), interpret the results, and prepare a
bid. One industry source indicated that in an area -where no geophysical
surveys have been conducted previously, this process-will take at-least a
year; if some surveys already exist, this process can be reduced to six
months. Where the final notice is issued 1-2 months before the sale, industry
must make the often sizable investment in exploration before there is assur-
ance that the tracts will be offered. Industry is generally willing to do
this because most of these programs have a fair amount of predictability.
While doubts may remain regarding the specific terms and conditions of sale,
there is a high probability that a large proportion of the tracts under
consideration-will ultimately be offered.

Currently there is no such predictability or assurance in North Carolina.
Given the importance of the fishing and tourist industries, the public concern
for environmental quality, the lack of recent experience with oil and gas
operations, and the state's recent positions on OCS sales, it is possible that

11Commonwealth of Virginia, State Minerals Management Plan, prepared by
the Department of Conservation and Economic Development,.Division of Mineral
Resources, in cooperation with the Department of General Services, Division of
Engineering and Buildings (n.p., 1983); Robert G. Doyle, "Review and Revision
of Delaware Mineral Laws, Including Draft Legislation," prepared by the
Delaware Geological Survey under contract to the office of Management, Budget,
and Planning (Newark, Del.,-@1981)

Table 5-5

Suggested Timetable for Proposed Review Process (EIS Option)

Time
(in months) Events

Land Resources receives application, reviews with assistance
from others, and rejects, defers, or makes recommendation to
secretary.

Secretary appoints working group; group considers proposal,
consults others, recommends to: reject, approve.with
negative declaration, or approvewith EIS.

4-6 EIS written

2 Draft EIS sent to Secretary, circulated -within Department,
revised as appropriate and sent to clearinghouse.

2 Clearinghouse circulates, also sent to federal agencies;
public notice and hearing(s)

2 Comments reviewed; EIS revised; Final EIS and proposed
notice of sale issued.

2 Proposed notice circulates; comments received; notice
revised if necessary; approval obtained from Administration,
Governor and Council of State; final notice issued.

14-16 months Total from application to final notice of sale

only a small percentage, if any, of the acreage applied for will be offered,
at least until experience with leasing increases. Under these circumstances,
exploration undertaken before the final notice may very well be wasted.
Fearing this, and given only 1-2 months between notice and sale, companies may
choose not to participate or may explore only sparingly. To eliminate the
possibility of wasted exploration and thereby improve economic efficiency,
reduce uncertainty, encourage greater industry participation and increase
bids, the state should give serious thought to timing the sale so that
companies have time to conduct adequate exploration programs after the final,
or at least proposed, notice of sale. Interested companies can best advise on
the time needed, but it would appear to require 6-12 months after the proposed
or final notice.

There are disadvantages with this timing as well. The sale is postponed
that much longer and companies may lose interest or the market may change.

The applica nt, who must explore early to know which tracts to apply for, is
penalized. Pragmatically such timing also gives groups seeking to disrupt the
sale that much longer to marshal their forces and get to court. Nevertheless,
allowing sufficient time for exploration after a sale notice seems to have
sufficient merit to deserve testing.

An Alternative Leasing Process

If the state should decide instead to pursue a more aggressive approach,
with active promotion of oil and gas development, there are several changes
that can be made in the procedures outlined above to accomplish this without
sacrificing environmental safeguards. In general, the state should consider
adopting more of an OCS-like process. This might include:

(1) a clear announcement by the state of its intent to hold a lease sale
(presumably following a finding that such a sale is in "the best interest of
the State" and that development of sale leases could be done under existing
environmental laws);

(2) a systematic effort to solicit expressions of industry interestV
through a call for nominations.or similar means;

(3) encouragement of geological and geophysical exploration of state
waters on an on-going basis, independent of specific sales; and

(4) assignment to one office or committee of the responsibility to guide
lease sale proposals through the review process and to,promote sales to the
full extent allowed by other program objectives and by existing environmental
and other laws.

Economic incentives are another powerful way to promote exploration and
development; these are discussed in section 5.6.

5.3 Protection of Environmental and Economic Resources

Protection of the natural environment and of existing economic activities
will be a major focus of any leasing program. The quality of the coastal
environment is held in high regard in North Carolina and largely determines
the success of the fishing and tourist industries, two of the mainstays of the
coastal economy.

How such protection is achieved is the subject of this subchapter. our
concern here is with general strategies for protection, and not with the
specific details of individual measures, which are better left to NRCD
personnel. The subchapter addresses five topics: (a) the various avenues
or vehicles available to the state for achieving environmental protection;
(b) approaches to reducing general types of impacts; (c) organization and
research for environmental protection; (d) the need for pre-sale review and
coordination; and (e) leases of privately owned submerged lands.

Avenues for Protection of Environmental Resources

Five avenues or vehicles for protecting environmental and economic
resources from the undesirable impacts of oil and gas development are
available to the state. These are:

1. the decision of which areas to offer for lease;

2. eligibility criteria for bidders;

3. lease terms and stipulations;

4. regulations on operations conducted pursuant to the lease; and

5. other laws, regulations, and permits.

The first four of these are available to the state in its role as a landowner,
with resources to sell, while the last stems from the state's authority to
regulate public and private activities under the police power.

Decision of what areas to offer for lease. The decision not to offer an area
for lease provides the most basic and reliable protection available. If
development of an area, regardless of how it is conducted, would result in
adverse impacts or risks greater than potential benefits, this decision is
appropriate. However, since refusal to lease postpones indefinitely the
benefits that might accrue from development, this,decision should only be used
as a last resort, after the statehas determined that all other available
measures are inadequate to protect the resource.

it is important to keep in mind here the distinction between leasing and
drilling. A lease does not give the lessee permission to drill at any point
within its boundaries nor is such permission necessary to develop the tract's
hydrocarbon resources. Depending on economic considerations and reservoir,
hydrocarbon, and well characteristics, a single well may be used drain tens or
even hundreds of acres. In addition, directional drilling allows bottom hole
locations to be reached hundreds or thousands of feet horizontally from the
drilling rig.12 The combined result is that the oil and gas resources
underneath large areas may be removed from a single surface location.
Directional drilling has technical limits, of course, and there are certain
disadvantages to its use: it is costlier, more time consuming, riskier, and
makes subsurface geological interpretation and formation evaluation more
difficult than do vertical boreholes.13 The point to be made is that, where

12Seel, e.g., B.E. Cox and W.A. Bruha, "Curved Well Conductors and
Offshore Platform Hydrocarbon Development," OTC Paper 2621, pp. 19-29 in:
Eighth Annual Offshore Technology Conference Proceedings, Vol. 3 (Dallas:
OTC, 1976).

13See American Petroleum Institute, API Recommended Practice for Drill
Stem Design and Operating Limits, 10th ed., Publication API RP 7G (Dallas:
API, 1981), Section 6: "Limitations Related to Hole Deviation"; California
State Lands Commission, "Staff Report on Current Status of Proposed Ft.

surface loc=ion is a concern, a lease with surface restrictions may permit
the oil and gas resources to be extracted while achieving the same measure of
protection as a decision not to lease.

This is just one example of the factors the state should consider. For
each impact, the relevant question should be: are there measures available,
be they certain technologies, restrictions on operations, or other means, that
can limit adverse impacts to acceptable levels without withdrawing the area
from availability altogether?

-Two levels of this type of review are possible. It may be done in
connection with a specific lease proposal, with consideration limited to the
area covered by the application. Or at any time, irrespective of pending
applications, the state may wish to consider establishing a leasing moratorium
within a specified area, be it a few acres or the state's entire jurisdiction.
The purpose would be to announce to industry that the state will not approve
applications in these areas under any conditions, and so save industry the
cost of preparing those applications and the state the time and effort needed
to individually review them. The disadvantages of such a moratorium are that
(a) it is an additional administrative chore that may be time wasted if the
policy is never needed, (b) time limits or conditions under which the policy
would be reviewed must be set, and (c) the state may include areas without
examining alternative restrictions that offer the desired level of
protection.

Leasing moratoria tend to be tools of the legislative rather than the
executive branch. The Alaskan and Californian legislatures and the U.S.
Congress have all passed laws prohibiting leasing on portions of their
respective jurisdictions.14

It is recommended that the state not consider a moratorium separately but
that the question of a moratorium be raised as 4 natural response to any
rejected-application if the reasons for the rejection so indicate. Should the
state wish to establish a formal leasing moratorium in a certain area, there
should be a review with public hearing to establish where, how long, and why.
The moratorium could even be promulgated as a rule.

Eligibility criteria for bidders. Eligibility criteria for bidding are dis-
cussed at length in Section 5.6. They are mentioned here because it is
conceivable that one criterion be that a company have a good environmental
record, or more specifically, that the company have shown good faith in com-
plying with environmental laws and regulations. This option presents two
difficulties. The definitions or standards needed to apply such a criterion
fairly would be difficult to formulate. Moreover, lessees often hire drilling
contractors, and the environmental record of the lessee may bear little
relation to that of the contractor. However, liability is not necessarily

Conception/Pt. Arguello Oil and Gas Leasing Program," Dec. 15, 1982, mimeo,
p.49.
14Alaska Stat. �38.05.184; Calif. Public Resources Code ��6870, 6871.1,
6871.2; 43 U.S.C. �1340(h).

transferred from the lessee to the driller, so that the environmental record
of the lessee would reflect that of the contractors it hires and could be
considered by the state. A more feasible option might be to require state
approval of the driller before the lessee could begin operations. Such
approval might be contingent, at least, on the driller's having had experience
in environments similar to that of the lease, and if suitable criteria can be
devised, on the driller's having shown good faith in complying with drilling
regulations, environmental permits, and the like.

Lease terms and stipulations. Provisions for environmental protection can be
inserted as terms in the lease itself or attached as stipulations. The lease
should be a fairly standard document that can be used with minor modifications
throughout the state's jurisdiction. Stipulations, on the other hand, are
attached to the lease on a case-by-case'basis and are designed to deal with
environmental or other problems specific to that tract.

Perhaps the most important lease provision from an environmental perspec-
tive is the one that binds the lessee to compliance with the leasing statute,
its regulations, and all other applicable statutes and regulations. If an
environmental statute is violated, this provision makes the lessee liable not
only for the penalties listed in the statute, but for loss of the lease as
well. Other provisions of the lease may address such concerns as safety
requirements, plans of operation, surety bonds, and property removal (see
Appendix F).

Stipulations are used to address a wide variety of subjects, and their
use in a given situation is limited only by the creativity of the authors and
the willingness of companies to bid on the product to which they are attached.
Some stipulations work on a contingency basis, with the lessor authorized to,
require certain measures if a study so indicates or a specified event or
discovery occurs. The best way to describe how stipulations may be used is to
provide some illustrations (Table 5-6).

operating regulations and requirements. In many programs the leasing agency
is authorized under state law to adopt regulations governing lease operations.
While most of these requirements could be included in the lease, not doing so
keeps the lease form simple and allows the regulations to be amended as
technology changes and our environmental knowledge improves. Such regulations
may contain specific environmental safeguards, or they may establish proce-
dures and standards for approval of certain operations; the Minerals Manage-
ment Service's OCS regulations (30 CFR 250 and OCS operating Orders) provide
several examples of each. Topics that might be covered by such regulations
include drilling requirements, oil spill contingency plans, plans of opera-
tions, environmental reports, and worker safety requirements, among others.

What operating regulations a program adopts will depend in part on
whether other agencies already regulate the target activities. Most states,
for instance, have oil and gas boards that regulate drilling operations, so
most leasing agencies leave this function to them.

The advantage of such regulatory authority is that, because the
operations are on state lands, the grant of authority is much broader and the

Table 5-6

Examples of Stipulations Attached to offshore oil and Gas Leases

Subject of Stipulation and Description of Stipuatlion as
Recent Sale in Which Employed Used in that Sale

Geological Requires lessee to demonstrate that opera-
(OCS Sale 56) tions can be conducted safely on portions
of tracts identified as being susceptible
to mass movements of sediment.

Cultural Resources Allows lessor to require remote sensing
(OCS Sale 78) surveys for cultural resources and pro-
tection for any resources located.

Biological Resources Requires surveys and protection 'for hard
(OCS Sale 78) bottom areas and protection for other
significant biological resources.

Fisheries Training Program Requires lessee's supervisors and vessel
(Calif. Pt. Conception Sale*) operators to become familiar with cour-
mercial fishing operations and potential
conflicts with the fishing industry.

Oil Spill Response Capability Establishes lessee's responsibilities for
(Calif. Pt. Conception Sale) maintaining an oil spill response capa-
bility and for funding related programs.

Drilling Muds and Cuttings Prohibits discharge of drilling muds and
(Calif. Pt. Conception Sale) cuttings.into the marine environment.

Subsea Completions Allows lessor to require subsea completions
(Calif. Pt. Conception Sale) rather than fixed platforms wherever
specified factors so indicate.

Seasonal Drilling Restriction Requires lessee to restrict drilling
(Alaska Sale 39) activities during fall bowhead whale
migration and to fund appropriate studies
at state's direction.

Military Areas Limits government liability for military
(OCS Sale 78) accidents and requires operational agree-
ments and control of electro-magnetic
emissions for tracts subject to joint
use by military.

Undetonated Explosives Requires lessee to conduct additional
(OCS Sale 78) surveys,if lessor believes unexploded
ordnance exists in lease area.

Table 5-6 (continued)

Subject of Stipulation and Description of Stipuatlion as
Recent Sale in Which Employed Used in that Sale

Transportation Requires transportation of petroleum by
(OCS Sale 56) pipeline rather than tanker, wherever
practicable, and establishes certain
guidelines for the use of both.

Labor Requirement Requires that lessee's labor force be
(Calif. Pt. Conception Sale) comprised of U.S. citizens and permanent
resident aliens.

Special Studies Establishes lessee's financial responsi-
(Calif. Pt. Conception Sale) bility for specific studies as the
state may require.

*California stipulations are technically called "Special operating
Requirements" and are listed in Exhibit C of the lease.

topics that may be addressed less restricted than under standard environmental
statutes (including oil and gas conservation acts). As a result, leasing
agencies often use such regulations to "fill in the gaps" so to speak, i.e.,
to address concerns that the existing regulatory scheme does not. The need to
review the responsibilities and capabilities of the different regulatory
agencies in a state and to coordinate their responses with that of the leasing
agency is evident.

Aproblem arises in North Carolina in that the authority to adopt such
regulations is vested in the Department of Administration, not NRCD. N.C.
Gen. Stat. �146-8 makes no mention of rules. Section 146-2 states, "The power
to manage, control, and dispose of . . . submerged lands is hereby vested in
the Department of Administration . . .;" and confers upon Administration the
power "to adopt such rules and regulations as it may deem necessary to carry
out its duties under the provisions of this subchapter." Under these circum-
stances, the state would seem to have three options:

(1) Not attempt to regulate lease operations beyond what is provided for
in lease provisions and existing regulatory statutes. Some requirements can
be included in the lease itself; Alaska, for instance, includes requirements
for the submission and approval of a plan of operations in the lease, but
regulations elsewhere expand on it. This approach works well for simple
requirements but less so for complex ones, particularly if they involve
lengthy review procedures.

(2) Promulgate regulations by the Department of Administration. This is
not advisable for several reasons. The types of regulations envisioned deal
with oil and gas technologies and environmental impacts and mitigation; the
,expertise to promulgate and enforce these regulations already exists in NRCD

for the most part, and not in Administration. Moreover NRCD already has
responsibility for developing the lease proposal and for granting most of the
permits needed to develop the lease.

(3) Request the General Assembly to amend �146-8 to provide NRCD with
appropriate rule-making authority. The amendment might read: "Other
provisions of this subchapter notwithstanding, the Secretary of the Department
of Natural Resources and Community Development may adopt and enforce rules and
regulations governing mineral operations conducted pursuant to a sale, lease,
or other disposition under this section."

other statutes, regulations, and permits. Most of the potential impacts of
oil and gas development are addressed by existing statutes, regulations, and
permit requirements. These are reviewed in ChapterThree and Appendix E. The
conditions attached to issuance of some of these permits, particularly the
CAMA Major, NPDES, and Sections 10/404 permits, will be key to the levels of
impact generated by lease operations.

Approaches to Reducing Specific Types of Impacts

In Appendix D, the major environmental impacts of oil and gas activities
were reviewed. It is appropriate now to examine each of these categories in
terms of how North Carolina might respond to potential impacts. Table 5-7
lists both existing statutory authorities and approaches other programs have
taken that North Carolina might consider. Since the state could respond to
any of these impacts (except those from geophysical exploration) by refusing
to lease the area, this option is not listed. Chapter Three and Appendix E
provide details on the laws and permits mentioned.

Research for Environmental Protection

During the course of review many questions may be raised which cannot be
answered immediately but which are amenable to research. Studies programs to
address these questions are integral parts of some leasing programs,
particularly those of California and the U.S. Such studies may be of several
types: geologic and geophysical surveys to estimate hydrocarbon potential;
geohazard and cultural resource surveys to identify these types of site
specific risks; characterization studies of biota found on the tract(s); fates
and effects studies of discharged substances; and monitoring studies to detect
environmental changes during oil and gas operations.

There are four possible sources of funding for these studies: direct
legislative appropriations, the companies themselves, existing grant programs
(Coastal Energy Impact Program, Sea Grant, Water Resources Research Institute,
etc.), and regular agency budgets. A distinct studies program, focussed
specifically on leasing questions and funded at least initially by the General
Assembly, will provide the best chance that the studies will be well coordi-
nated and that the highest priority studies will be funded first. Lessees
might be required to reimburse the state for pre-sale studies, or alterna-
tively, the cost might be taken out of sale proceeds. These proceeds might
also provide a source of long-term funding.

Table 5-7. Measures for Reducing the Impacts of Petroleum Development in
North Carolina's Submerged Lands.

Im2act Category and Subcategory Measures Available for Use in North Carolina

Geophysical Exploration Geophysical exploration permit* (needs improvement)
CAMA permit* (in some cases)
See also navigational hazards, below

Dredging and Filling
general environmental disturbance �10, �404 permits from the Corps,* NEPA*
State dredge and fill permit*
CAMA major permit*
Easements from DOA for platforms, pipelines, and other
facilities*
Biological resources stipulation (OCS Sale 78)
disturbance of cultural resources Corps permits,* National Historic Preservation Act of 1966*
CAMA major permit,* G.S. �121-12a,* Archives and History
Act*
Cultural resources stipulation (OCS Sale 78)

Presence of Structures and Boats
navigational hazards of 610 permit from Corps*
structures Aids to Navigation on Artificial Islands and Fixed
Structures.(33 CFR 67)*
Easements from DOA for platforms and other fixed
facilities*
Navigational charts, Marine Broadcasts, and Local Notices
to Mariners*

navigational hazards and con- Navigational charts, Marine Broadcasts, and Local Notices
flicts of increased traffic to Mariners*
Fisheries Training Program stipulation (OCS Sale 42,
Calif.)*
Alaska stipulation restricting surface use under certain
conditions
Arbitration procedures for settling claims (Calif.)
trash and debris Required marking of materials (OCS Order 1)
Gear loss funds (U.S., Louisiana)
loss of access CAMA major permit*
Pipeline regulations and stipulation (U.S.)
military conflict Coordination with Department of Defense
visual impact Subsea completions stipulation (Calif.)

Oil spills
prevention Drilling regulations under Oil and Gas Conservation
Act* (need improvement; see, e.g., OCS Operating
Orders, regulations of states' Oil and Gas Boards
or equivalent)
Other operating regulations (30 CFR 250 and OCS Operating
Orders)
clean-up Operator oil spill contingency plan required by regulation,
stipulation, or permit condition (OCS Order 7)
Oil spill response capability stipulation (Calif.)
Federal contingency plans (national, regional, local) under
Federal Water Pollution Control Act �311, as amended*
State contingency plan under N.C. Oil Pollution and
Hazardous Substances Control Act of 1978*

liability and recovery for Federal Water Pollution
damages

Table 5-7. (continued)

Impact Cate-g2.Ly and Subcategory Measures Available for Use in North Carolina

Oil Spills (continued)
liability and recovery for Federal Water Pollution Control Act �311, as amended*
damages N.C. Oil Pollution and Hazardous Substances Control
Act of 1978*
compensation fund (U.S. Offshore Oil Pollution Compen-
sation Fund under 43 U.S.C. ��1811-1824)
evidence of operator's financial responsibility by
bond, insurance, etc. (43 U.S.C. �1815)
arbitration procedure for settling claims (Alabama)

Drilling Fluids and Cuttings, Federal Water Pollution Control Act, NPDES permit,
Formation Waters, and Other and 6401 water quality certification*
Discharges State water pollution control statutes and pemits*
Regulations for preventing pollution (OCS Order 7)
Stipulations on pollution discharges (Calif.)

Air Pollution Clean Air Act and PSD program*
State air quality permit*
Regulation or stipulation requiring hydrogen sulfide
contingency plan (Alabama, Calif.)

Employment Labor stipulation (Calif.)

*Currently in effect in North Carolina

Some questions may need to be answered before the state will be willing
to consider leasing; these are typically addressed by program directed and
funded studies. Other questions may not be critical to the leasing decision
itself but do relate to what types of restrictions on operations are appro-
priate. Studies directed at these questions can be provided for by lease
stipulations requiring the lessee to fund or undertake these studies at the
state's direction.

The Need for Pre-Sale Review and Coordination

The need for consultation and coordination among environmental agencies
during lease sale review cannot be emphasized enough. Three reasons for
extensive coordination at this stage exist:

(1) The ability of the state, through lease terms and stipulations,. to
impose virtually any requirement deemed in the public interest on the lessee
was mentioned earlier as an important means of protecting environmental
resources. Once the lease is signed, this opportunity is lost. It is
essential, therefore, that the state make a concerted effort during sale
review to anticipate the adverse impacts of the sale and to ensure that they
are addressed either by existing or proposed laws and regulations or by lease
terms and stipulations. Part of the substantive review of the first lease
application should be a thorough review of existing laws and regulations and a
program for upgrading them where necessary.

(2) In issuing a lease and accepting compensation for it, the state has
implied that it believes the lease can be developed with no unreasonable
expenses required beyond the terms and requirements announced in the notice of
sale. In the interest of fairness, if nothing else, the state has an obli-
gation to make a good faith effort to identify any major regulatory hurdles to
development of the tract.

(3) The higher the risk perceived by industry that additional, unex-
pected regulatory costs -will be imposed on the lessee, the lower the bids (and
perhaps the competition) will be. This perceived risk can only be reduced
with time. A concerted and visible state effort before the first sale to
identify environmental problems and their regulatory solutions may instill
confidence in industry and be reflected in sale bids. However, this risk will
be reduced in the long run only if the state can establish a track record of
not imposing major unexpected costs after the lease is executed, something
that can only be accomplished if extensive review and coordination precede the
sale.

Leases of Privately Owned Submerged Lands

If some private fee simple or mineral interests in submerged lands should
be found to be valid (see section 5.4), the state must recognize the possi-
bility that these lands might also be leased for petroleum exploration and
development. If this occurs, the state's role will be restricted to that of
regulator of activities on private property (the fifth of the five vehicles
for environmental protection discussed earlier in this section). Opportuni-
ties for some types of restrictions and for control over the rate of leasing
will no longer be present. However, existing regulatory statutes, particu-
larly the oil and Gas Conservation Act, CAMA, the Federal Water Pollution
Control Act, and others, provide authority for a substantial degree of control
over oil and gas activities regardless of land ownership.

It is therefore recommended that (1) the implications of the findings of
the existing Submerged Lands Task Force for private oil and gas leasing be
kept in mind, and (2) during the course of review of existing authorities in
conjunction with the first lease application, or sooner if needed, state
regulatory authority should be reviewed to determine whether it alone is
currently adequate to control the adverse impacts of submerged lands petroleum
.development.

5.4 Area and Rate of Leasing

In considering the leasing of state-owned submerged lands, two of the
most basic questions to be asked are: what areas should (or could) be offered
for lease, and at what rate should they be offered? There are a number of
factors that ought to be included in any consideration of the public interest,
and the more significant of these are discussed below:

Environmental Sensitivity

Are the areas under consideration environmentally sensitive? Can leasing
impacts on these areas be limited to acceptable levels? These are probably
the most important questions in deciding whether a tract should be made
available for lease, and are discussed in detail in sections 5.2 (The Leasing
Process) and 5.3 (Protection of Environmental and Economic Resources).

Tract Size and Shape

What is an appropriate size and configuration for a lease tract? In the
past it has been North Carolina's practice to lease huge tracts (hundreds of
thousands of acres) for exploration, with the lessee retaining the right, upon
completion of a.producing well, to select and hold blocks of up to 750,000
Acres, depending on the lease (Figure 2.3). There are several reasons why
tracts this large should not be leased:

1) Such a lease eliminates the primary means through which the state can
control the rate and location of development. With smaller blocks, the state
can slow the pace of development by reducing the acreage let, or speed it up
by issuing a number of leases simultaneously, each with its standard require-
ment that drilling must be begun within the primary term or the lease will be
cancelled.

2) Large lease tracts transfer all-the resources within large areas to
the lessees at the agreed upon terms, which in a frontier area may be quite
modest. Should a commercial field be discovered, the enhanced value of the
lands surrounding the discovery will accrue mostly to the lessees, while with
smaller blocks, the state would realize large gains from nearby unleased
tracts.

3) The costof leasing such large areas may be sufficient to drive
smaller firms out of the market, reducing,competition and probably reducing
the size of bids on a per-acre basis.

The practice of other programs regarding offshore lease tract size is
shown in Table 5-8. Notice that the tracts in all of these programs are less
than 6,000 acres. Industry has generally expressed satisfaction with a 5,000-
6,000 acre tract size.

Several factors should be considered in choosing an appropriate tract
size or size range. On the one hand, tracts should be small enough to allow
the state to retain a fair degree of control over the location and rate of

Table 5-8

Lease Tract Size in Selected Leasing Programs

(all tract sizes in acres)

Maximum Tract Size Tract Sizes in a
Established by: Recent Sale:1

Administrative
Program Statute Policy Range Average

Alabama 5200 29-5164 3709

Alaska 5760 3824-5760 5108

California 5760 4898-5742 5118

Louisiana 5000 2500 282-2503 1608

Mississippi 6000 2880 1177-2880 2563

Texas 1440 5-1440 945

U.S. 57602 5693 5693

lAlabama 1981 offshore sale; Alaska Lease Sale 39; California Point
Conception Sale; Louisiana 3 March 1983 Sale; Mississippi Lease Sale No. 1;
Texas 5 October 1983 Sale, Group IV; U.S. OCS Sale 56.
2"unless the Secretary finds that a larger area is necessary to comprise a
reasonable economic production unit" (43 U.S.C. �1337(b)).

development, to provide the state with some of the benefits of land values
increased by a discovery, and to keep tract bonuses sufficiently low to
encourage competition. on the other hand, tracts should be large enough to
compensate the lessee for the riskiness of the investment. A case can be made
that in low potential wildcat areas such as eastern North Carolina, relatively
larger tracts are needed to accomplish this. Given the experience of other
programs, it is suggested that the state adopt as standard practice a lease
tract size in the 5,000-6,000 acre range, but that, on a case-by-case basis,
industry be given the opportunity to demonstrate that a larger tract size
would be more suited to the particular circumstances of the area being
considered.

How should lease tract boundaries be determined? The state clearly has
an interest in an orderly configuration that facilitates the leasing of

adjacent areas and the re-leasing of quitclaimed leases, and that minimizes
problems between adjacent lesses. The simplest pattern is a square or rec-
tangular grid. The grid used in the OCS program-consists of square blocks
blocks 4800 meters on a side, each containing 2304 hectares (5693 acres).
Block boundaries are defined in terms of X and Y coordinates of the Universal
Transverse Mercator (UTM) Grid System, and the location and boundaries of
these blocks are shown on OCS Official Protraction Diagrams issued by the
Minerals Management Service. These blocks are everywhere square and identical
in size, except in two circumstances: 'at the territorial boundary between
state and federal waters, where block boundaries may be irregular, and along
certain lines of longitude where, because of an artifact in the UTM grid that
results from attempting to place a square grid on the earth's curved surface,
columns of blocks adjacent to particular longitudinal lines slowly narrow in
width as one moves northward. one such line of longitude is 780 W, which
occurs just west of Cape Fear.

Where a partial block occurs on the OCS, depending on its size it is
either leased separately or combined with an adjacent block to comprise a unit
large enough for economical development. Tracts offered for lease may also be
less than a full block where a portion of the block is excluded for environ-
mental or other reasons, such as the existence of a marine sanctuary.

Five of the six states examined use a grid system to some extent, though
they often subdivide the larger blocks, sometimes into irregularly shaped
parcels. Texas and Louisiana rely on an extension of the OCS grid into state
wat.ers. Alabama uses a 15,000 ft. grid, resulting in blocks of 5164 acres;
Mississippi uses a three-statute-mile grid with blocks of 5760 acres, and
Alaska uses an extension of its township and range survey to define offshore
tracts of one to nine sections (each section being 640 acres, or one square
mile). California was guided by three considerations in dividing the 40,000
acre Point Conception sale area into tracts. (1) a statutory limit on tract
size of 5760 acres; (2) staff interest in keeping tract boundaries from
crossing identified geologic structures (such a configuration, they claimed,
would provide for simpler reservoir control, the potential for reduction in
number of development programs, greater ease in program administration,
probably fewer platforms and associated facilities, and less accounting
problems); and (3) industry interest in constructing boundaries so that the
corners coincide as much as possible with the corners of adjacent federal
leases, so as to reduce the difficulties.In unit or coo erative development
should any reservoirs cross the state/federal boun-.7. The result was the
tract configuration shown in Figure 5-4.

Though the use of promising geologic structures to define tract boundaries
has merit, it also has disadvantages. Such a,,scheme requires the acquisition
of a substantial amount of non-proprietary geologic data, something California
was willing to buy but most states are not. Even if the data are acquired,.
there is no guarantee that the state's predictions of reservoir location are
correct. Furthermore, unitization was designed to deal with precisely these
problems. Such boundaries also result in irregular tract parcels that may not

15California State Lands Commission, "Staff Report on Current Status of
Proposed Pt. Conception/Pt. Arguello Oil and Gas Leasing Program," Nov. 29,
1982, mimeo, pp. 24-25.

Figure 5-4

Lease Tract Configuration for California's Point Conception Sale

The 40,000-acre sale area between Point Arguello and Point Concep-
tion was divided into 8 tracts. Potential petroleum bearing struc-
tures and existing state and OCS lease tracts and lessees are
identified. (From California State Lands Commission, "Staff Report
on Current Status of Proposed Pt. Conception/Pt. Arguello Oil and
Gas Leasing Program," Dec. 15, 1982, mimeo, p. 85.)

'Ou
Q'i
P-OW0 P-0440 P-0441
POINT ?
ARC

P-0443 TR&CT*33 P-044
4

7.: J
P-0443
P-04 46 P-0447 P-0448
03
79-464 CHVVNqW CRIVININ CNVAqM Of
1
P-0459 P-0453
P-0449 P-0430 P-04SI
41 POINT
CONCEPTI N,
P-0315 P-030 "Sol PO
MOBIL

PNC
P-0457 P.0319 P-03to P-0321 TRACT 9

3 1
to %TAVN92
RVNOH EXXON # IIA UNIT
P-0197 P-0196 Pot"
P-03211 P-0323 PO5t4

create many problems where two sides of the tracts are already defined (as in
California), but might create administrative headaches in large open water
areas like Pamlico Sound.

A grid system, particulary one that is compatible with the OCS grid, has
much to recommend it. Boundary selection requires and assumes no geologic
knowledge. The entire area is automatically divided into compact, manageable
blocks that facilitate their leasing and re-leasing. The number of leases
adjacent to any single lease is kept relatively small, making unit operations
simpler. Coordination with OCS lessees at the state-federal boundary is also
easier.

In 1978, in response to concerns that previous North Carolina lease tracts
had been too large, the Department of Natural Resources and Community Develop-
ment began the process of extending the OCS grid into North Carolina waters
with the intention that future leasing be done in multiples of these 2,304-

hectare blocks. The Land Resources Information Service is currently engaged
in this work.

The continued use of this grid for defining lease blocks is recommended.
At some point in the future, the state may wish to consider subdividing these
blocks, as is done in several other states. For now, however, it is recom-
mended that tracts of 2304 hectares be offered for lease, except where
industry can demonstrate that tracts comprised of 2 or more of these blocks
are preferable. As with the OCS program, partial blocks may be leased
separately or attached to an adjacent block.

one final point. In Louisiana, companies may submit bids for portions of
offered tracts. Not only does this create problems in evaluating bids (dis-
cussed later), but it may also create the irregular boundary problems that a
grid system is designed to alleviate. None of the other programs permit bids
on less than a full tract,16 and North Carolina should not either.

Clear Title

There are two sources of potential title conflict regarding the state's
ability to lease oil and gas rights in a specific parcel. First, there may be
disagreement over the location of the boundaries between the state's lands and
those of the federal government, adjacent states, and upland owners.
Secondly, there may be disagreement over whether the state has disposed of
certain interests in these lands, and what rights regarding use of the surface
the state has retained and can be conveyed to a mineral lessee.

Boundaries. For the Atlantic states, including North Carolina, the boundary
between state and federal jurisdiction over the seabed was established by
Congress in the Submerged Lands Act of 1953 as three geographica '1 or nautical
miles seaward of the coastline, measured from ordinary low water*17 This
boundary was subsequently upheld by the Supreme Court in 1975 in United
States v. Maine.18

Where the coastline is relatively straight and unbroken, this three-mile
line is relatively easy to locate. Where the coastline is broken by inlets,
bays, and islands, however, the boundary is more difficult to determine. For
these coastlines the Submerged Lands Act is ambiguous in defining:'the baseline
from which the three miles are measured, with the result that the Supreme
Court has had to resolve a number of disputes between the U.S. and coastal

161n its 1982 offshore sale Alabama allowed bids on quarter blocks for
one of the twelve tracts offered; there is no consensus on whether partial
block bidding will be permitted in the future.

1743 U.S.C. ��1301-1315.

18420 U.S. 515 (1975).

states over the last twenty-five years.19 While a number of general rules for
locating the baseline have been established by the Court, the application of
these rules to the peculiar circumstances of individual coastlines continues
to be a source of conflict, and Alaska, Alabama, and Mississippi are all
currently in various stages of litigation with the U.S. over boundary
location.

Even when all disputes over the construction of these rules are eventually
resolved, one issue threatens to provide a source of continuing trouble.
According to the concept of ambulatory boundaries, which the Supreme Court
first adopted in 1965 in United States v. California2O and has since applied
in other submerged lands cases, the offshore federal/state boundary remains a
fixed distance (three nautical miles on the East Coast) from the existing
coastline. As the coastline changes, then, so does the offshore boundary.
Several authors have pointed out that the concept of ambulatory boundaries is
a sound one in international law, as a nation's territorial sea should retain
the same width regardless of coastal erosion and accretion. The concept is a
terrible one to use in establishing property rights, however, and creates
uncertainty in the conferring of long-term leases and may lead to protracted
litigation.21

19The main ambiguity was in the meaning of the term "inland waters" as
used to define the coastline in Section 2 of the Act. In 1965 the Supreme
Court adopted for use the definition of the term found in the Convention on
the Territorial Sea and the Contiguous Zone, an international treaty ratified
by the U.S. a short time before. While the decision settled some disputes, it
also had the effect of injecting new ambiguities found in the Convention, such
as the use of the straight baselines method, the meaning of the term "historic
bay," and other matters. Many of these the court has since ruled upon. For a
fuller discussion of these controversies and the Supreme Court decisions, see:
Richard G. Hildreth and Ralph W. Johnson, Ocean and Coastal Law (Englewood
Cliffs, NJ: Prentice-Hall, 1983), 514 pp.; Thomas Suher and Keith Hennessee,
State and Federal Jurisdictional Conflicts in the Regulation of United States
Coastal Waters, Sea Grant Publication UNC-SG-74-05 (Raleigh, N.C.: University
of North Carolina Sea Grant Program, 1974), 75 pp.; John L. Taylor, "The
Settlement of Disputes Between Federal and State Governments Concerning
Offshore Petroleum Resources: Accommodation or Adjudication?" Harvard Int.
Law Journal 11:358-399, 1970.

20381 U.S. 139 (1965).

21Robert Kreuger, "The Background of the Continental Shelf and the Outer
Continental Shelf Lands Act," Nat. Res.' J. 10:463, 1970; Taylor, "Settlement
of Disputes Between Federal and State Governments," pp. 368 ff. A bill was
introduced recently in Congress to help remedy this situation. S. 1878,
entitled the "Seabed Boundary Act" and introduced Sept. 22, 1983, by Senator
Robert Dole, would establish a mechanism whereby a coastal state and the
federal government could voluntarily agree to permanently immobilize the
federal/state boundary. Whether states would avail themselves of such an
opportunity is an open question. For North Carolina, where the coastline is
generally receding and is expected to continue to do so, such an agreement
would make sense. The risk in such an agreement is that a major change in
direction by the Supreme Court could provide additional territory to states

The Minerals Management Service has undertaken a program to establish, at
least temporarily, federal/state boundaries with a maximum degree of
precision. The program is being undertaken by MMS's Cadastral Engineering
Section in Denver and involves use of the best available data to select
salient points along the baseline and a computer program to calculate boundary
location with a precision not.previously obtained. Charts showing these
boundaries are sent to regional MMS offices and then individual states for
review. The current schedule calls for the North Carolina coast to be done
during FY 84, with charts sent to the MKS Atlantic OCS office by Sept. 1,
1984.22 To protect the state's interest, the Department should carefully
inspect these charts and the various rules and interpretations upon which they
are based.

Fortunately North Carolina's tideland lateral boundaries with Virginia
and South Carolina are a simpler matter. Both boundaries have been
established by interstate compacts and are fixed precisely and in perpetuity.
In each case the agreement was enacted by the legislatures of the two states
concerned and ratified by the U.S. Congress.23

As for the upland boundaries of the state's submerged lands, N.C. Gen.
Stat. �77-20, passed in 1979, formally declares the seaward boundary of
private oceanfront property to be the mean high water mark, with the exception
of lands below mean high water where title has been specifically granted by
the state (see below). North Carolina has historically been a mean high water
state, and its Supreme Court has held so since 1817.24 While mean high water
may be difficult to locate with great percision,25 such precision is generally

that were not signatories to such an agreement, but the chances of this appear
remote.

22Lee Thormalen, Minerals Management Service, personal communications,
July 22 and November 3, 1983. The charts also depict the so-called "8g" line,
named after Section 8g of OCSLA, which provides for consultation with states
regarding the leasing of OCS lands within three miles of the federal/state
boundary that might contain hydrocarbon pools that straddle the boundary.

23These boundaries are described at N.C. Gen. Stat. �141-8 (Virginia) and
�141-7.1 (South Carolina); the 1981 amendment to the South Carolina boundary
merely changed the language to read identically to South Carolina's, and the
physical boundary itself was not altered. Congressional ratification of these
agreements may be found at 86 Stat. 1298 (Virginia) and 95 Stat. 988 (South
Carolina).
24McKenzie v. Hulet, 4 N.C. 613 (1817). See Daniel F. McLawhorn,
"Ownership of the Estuarine Lands in North Carolina: Has the Public Trust
Been Sold?" mimeo, North Carolina Department of Justice, Raleigh, N.C.,
32 pp.
25See Vann Irvin, "In Search of Mean High Tide," mimeo, Center for Urban
and Regional Studies, The University of North Carolina at Chapel Hill, Chapel
Hill, N.C., and Aaron L. Shalowitz, Shore and Sea Boundaries, 2 Vols.
(Washington, D.C.: Coast and Geodetic Survey, U.S. Department of Commerce,
1962-64).

unnecessary for the purposes of oil and gas leasing. Upland boundaries are
also ambulatory, however, and the same problems may arise as with the federal/
state boundary discussed earlier.26

Interests in Submerged Lands. When conflicts arose over oyster cultivation
rights in the early 19601s, the General Assembly enacted N.C. Gen. Stat. �113-
205i which required anyone "claiming title to any part of the bed lying under
navigable waters of any coastal county of North Carolina or any right of
fishery in navigable waters of any coastal county superior to that of the
general public" to register that claim with the state by Jan. 1, 1970.

Over 10,000 claims were eventually filed, some dating back to the colonial
period. Many were claims of fee title based on North Carolina's entry and
grant statutes and Board of Education deeds. others were based on licenses,
grants, and perpetual franchises for oyster cultivation issued under 19th
century statutes, oyster leases granted in this century, and a variety of
other interests. Certain interests in submerged lands continue to be granted
by the state, including shellfish leases issued by the Marine Fisheries
Commission and utility rights-of-way and easements for special water-dependent
uses granted by the State Property Office.

While some of these claims, particularly those based on recent grants, are
undoubtedly valid, many others are questionable. In some cases it appears
that the claims are for greater interests in land than were actually granted
by the state; in others, it is unclear exactly what interests were granted by
the state, or whether the state even had the authority to make such grants.
There is a dearth of relevant court cases on the subject, and the whole issue
is a confused and difficult one. A state task force comprised of representa-
tives from the Departments of Administration, Justice, and Natural Resources
and Community Development is currently reviewing the claims and formulating
policies to address the issue. This subject will not be dealt with further
here; for more information on the subject, see the papers by Rice, Earnhardt,
McLawhorn, and Marlow and Propst.27

26A receding shoreline will generally favor the state at the expense of
the upland,owner, but the state will be the loser on the backside of the
barrier islands if the islands continue their migration shoreward. Although
there has been little case law concerning the effect of shoreline changes on
mineral rights, one recent decision found the severed mineral estate to be
subject to gain or loss as a result of erosion or accretion. Nilsen v.
Tenneco Oil Co., (Okla. Sup. Ct.) 614 P.2d 36 (1980).
27David Rice, "Estuarine Land of North Carolina: Legal Aspect of_Owner-
ship, Use and Control," N.C. Law Rev. 46:779-812, 1968; Thomas W. Earnhardt,
"Defining Navigable Waters and the Application of the Public Trust Doctrine in
North Carolina: A History and Analysis," N.C. Law Rev. 49:888-920, 1971;
McLawhorn, "Ownership of the Estuarine Lands in North Carolina;" Kim Marlow
and Luther Propst, Annotated Bibli raphy: The Public Trust Doctrine in
Submerged Lands in North Carolina (Raleigh,. N.C.: UNC Sea Grant College
Program, 1983), 15 pp.

If a private interest in a parcel of submerged land is established as.
valid, a series of questions presents itself with respect to the state's
leasing of oil and gas rights:

(1) Did the state retain the parcel's mineral rights and the ability to
lease them?

(2) If the state leases the oil and gas rights, must the oil and gas
lessee obtain the consent of the surface owner/lessee to enter and use the
surface for exploration and development?

(3) If the oil and gas lessee has the right to enter and use the surface,
-.what is his liability for damages?

Unfortunately there are no simple answers to any of these questions.
There is virtually no case law on these subjects in North Carolina. In other
states there has been substantial litigation on some points but very little on
others, and on those aspects that have been litigated, the rulings have
sometimes been inconsistent. For a fuller discussion of these questions see
Williams and Meyers, Hemingway, and Kuntz;28 a brief summary of -their
conclusions on each of these questions is ventured below:

(1) Whether the state retained the mineral.rights and the ability to
develop (or lease) them will depend on the exact wording of the conveyance.
In general, a fee conveyance carries with it the mineral estate while an ease-
ment or leasehold does not, but exceptions exist.29

(2) It is generally accepted that ownership of oil and gas rights carries
with it, by implication, the means of enjoying the mineral estate. The owner
of oil and gas rights "has the right to enter upon and make reasonable use of
the surface in connection with exploring for and exploiting the mineral
deposits."30 A mineral owner is not liable for damages caused in the exercise
of this right, though some courts have ruled that he is obligated to minimize
such damages.

It is fairly clear that where surface easements or leaseholds are created
after a mineral leasehold, since the right of the mineral lessee to reasonable
use of the surface was granted (incident to the mineral lease) by the fee

28 Howard R. Williams and Charles J. Meyers, Oil and Gas Law, Volume 1
(New York: Matthew Bender, 1981 with 1982 suppl.); Richard Hemingway, The Law
of oil and Gas (St. Paul: West Publishing, 1971 with 1979 suppl.); Eugene
Kuntz, A Treatise on the Law of oil and Gas, Volume I (Cincinnati: W.H.
Anderson, 1962-with 1983 suppl.).
29Hemingway, Law of oil and Gas, p. 189.
30Kuntz, A Treatise on the Law of Oil and Gas, Vol. 1, p. 80. It should
also be noted, however, that such a right is subservient to certain public
rights, and that, regarding submerged lands, existing navigation and
environmental laws may sharply reduce the area within a lease available for
drilling operations.

owner before surface rights were granted to another party, the latter is
subject to the former's use of the surface.31

Where the surface easement or leas'e precedes the mineral lease in time,
however, the situation is more complicated. Some have argued successfully
that the easement owner or surface lessee can forbid an oil and gas lessee's
entry based on the covenant of quiet enjoyment that is usually implied in
conveyances of easements and leases for years. Decisions in some cases have
hinged on the exact wording of the surface lease, particularly whether the
lease referred to sufficiently specific surface uses as to have effected a
severance of the mineral estate.32 Case law is not consistent on this point.
Such conflicts are often avoided through the negotiation of a "Tenant's
Consent Agreement" between the oil and gas lessee and surface tenant for
payment of surface damages; the agreement subordinates the right of the prior
tenant to the oil and gas lessee.33

(3) The liability of oil and gas lessees for surface damages has been a
common subject of litigation. The general rule appears to be that where the
oil and gas leasehold was created first, the surface tenant is entitled to
compensation only when the oil and gas lessee's use of the surface becomes
unreasonable or excessive.34 Where the oil and gas lease is let after convey-
ance of a surface easement or.leasehold, the owner of the surface interest may
be entitled to compensation for all damages.35 Many contemporary leases
contain a "surface damage clause" that requires the oil and gas lessee to
compensate the surface owner or tenant for all damages caused by oil and gas
operations.36 Care must be taken in constructing such clauses to ensure that
all possible circumstances are covered. In North Carolina, for instance,
easements have not been required for projects involving normal riparian access
such as wharves, piers, and docks, and the interests of these owners should be
protected as well. In Alaska state leases, the mineral lessee is required to
make advance arrangements with the surface owner or tenant for payment of all
damages caused by the mineral lessee's use of the surface.37 If an agreement

31Williams and Meyers, Oil and Gas Law, Vol. 1, �218.3

321bid.

33Hemingway, Law of oil and Gas, P. 190.

34Decisions have fairly consistently held that under such circumstances,
the surface lessee must prove negligence on the part of the oil and gas lessee
to win damages. For examples involving oyster leases, see Vodopija v. Gulf
Refining Co., 198 F.2d 344 (1952), and Trosclair v. Superior Oil Co., 219
So.2d 278 (La.) (1969).

35Kuntz, A Treatise on the Law of Oil and Gas, Vol. 1, p. 207, but
exceptions exist; see, e.g., Jurisich v. Louisiana Southern Oil and Gas Co.,
284 So.2d 173 (La. App.) (1973).

36Williams and Meyers, Oil and Gas Law, Vol. 1, �218.11.

37Alaska Stat. �38.05.130

between the parties cannot be reached, the mineral lessee may enter the
surface after posting a bond deemed sufficient by the state.

It is apparent from these considerations that, when a tract is being con-
sidered for leasing, (a) all claims to interests in the tract should be
investigated and, where conflicts exist, resolved if possible, (b) questions
of access rights and liability should be researched and fully discussed for
the benefit of all parties, and (c) appropriate lease provisions should be
written into the oil and gas lease (and future shellfish leases?) to clarify
the obligations of the patties involvedt-an&to help prevent litigation.

To protect against the possibility that a successful claim may be pressed
against the state after an oil and gas lease has been sold, the current
Mississippi lease contains the following provision: "This lease is granted
and accepted without any warranty of title or accuracy of description, either
express or implied, and without any recourse against Lessor for return of any
payments, once made by Lessee." Several other states have similar clauses,
and warnings to this effect are commonly published in the final notice of
sale.

If a title dispute is identified before a lease sale, negotiation or
litigation may be used to quiet title. Alaska and the federal government, for
instance, have recently implemented a several-step process of fact-finding,
negotiation, and if necessary, litigation for.resolving their many outstanding
title disputes. Occasionally both parties to a title dispute may be
interested in seeing the land brought into production as soon as possible, in
which case they may enter into agreements for the issuance and administration
of leases, with the revenues deposited in an escrow account until the
dispute is resolved. Alaska, California, and federal law all authorize the
appropriate agencies to execute such agreements.38 Primarily for this reason,
Alaska and the U.S. held a joint lease sale for tracts in the Beaufort Sea in
1979.39

Checkerboard Leasing and Surrender Requirements

Some people have argued in favor of leasing schemes that generate infor-
mation on unleased areas. The rationale behind such schemes is that by making
more information available on unleased lands, uncertainty is reduced, and on
average, the state realizes a higher return. Though sometimes more informa-
tion will result in lower lease values, the net effect will tend to be posi-
tive, as the information will reduce-risk and allow companies to reduce the
risk premiums they must factor into their bids. Two options for generating
information on unleased areas are checkerboard leasing and surrender
requirements.

38Alaska Stat. �38.05.137; Cal. Public Resources Code �6813; 43 U.S.C.
�4732.

39Details of the joint sale are discussed in J.B. Jackson and F.N. Kurz,
Arctic Summary Report, January 1983, prepared for the OCS Oil and Gas Infor-
mation Program, Minerals Management Service (Reston, Va.: Rogers, Golden &
Halpern, Inc., 1983), pp. 19-27.

Checkerboard leasing. With this approach every other tract is leased in an
initial sale, and the remaining tracts are leased as information accumulates
from exploration of the initial tracts.40 The major advantage of this
approach is that if a commercial find is made, the government realizes the
dramatic rise in value of adjacent tracts. Such a scheme avoids the situation
in which an entire productive structure is leased initially at low terms.

Unfortunately there are several disadvantages to checkerboard leasing.
The lessees of initial tracts must be required to release their exploration
results before the sale of adjacent tracts, something they will be reluctant
to do and which may cause them to lower their bids on the initial tracts. If
the time between sales of adjacent tracts is long, field development will be
more difficult and costly. There is also a risk to the initial bidders that
the government may never lease the adjacent tracts, thereby increasing the
size of a find needed to make any discovery commercial and probably also
resulting in lower initial bids. Finally, in high-cost, high-risk frontier
areas, it may be necessary to offer an entire structure as incentive before
industry will be willing to bid.

Alberta has experimented with checkerboard leasing, and Canada uses a
variant of it offshore.41 California considered a checkerboard pattern for
the Point Conception sale, but concluded that it was not consistent with the
state's policy of encouraging consolidation of facilities and operations .42
No other states use checkboard leasing.

Surrender requirements. This approach entails use of large exploration leases
with smaller development selection rights. The lessee is initially granted an
extensive lease area, but after a certain period of time or when a discovery
is made, the lessee must select a portion of the tract to hold for development
and is required to surrender the rest. All of North Carolina's previous
leases. were of this type, and both Canada and Britain require licensees to
surrender at lease 50% of each lease tract.43 on the other hand, none of the
principal leasing programs in the U.S. include surrender requirements.

40Hayne E. Leland and Richard B. Norgaard, "An Economic Analysis of
Alternative Outer Continental Shelf Petroleum Leasing Policies," paper pre-
pared for the Office of Energy R and D Policy, National Science Foundation,
1974, 79 pp. (NTIS No. PB 285 823). Checkerboard leasing is discussed on
pp. 65-66.
41Ibid., p. 65; Michael Crommelin, "Offshore oil and Gas Rights: A
Comparative Study," Natural Resources Journal 14:475-6, 1974.
42California State Lands Commission, "Staff Report on Current Status of
Proposed Pt. Conception/Pt. Arguello Oil and Gas Leasing Program," Nov. 29,
1982, mimeo, p. 25.
43Crommelin, "Offshore Oil and Gas Rights," pp. 475-6; Kenneth W. Dam,
Oil Resources: Who Gets What How? (Chicago: Univ. of Chicago Press, 1976),
pp. 49-51.

The advantages of surrender requirements are similar to those of checker-
board leasing: less uncertainty and risk leading to higher government
revenues, and better information for government decision-makers. In this case
the exploratory data will be for land surrendered and available for leasing,
rather than simply adjacent blocks. However, surrender requirements also have
a number of disadvantages:

(a) exploration results must be made public;

(b) the larger size of exploration tracts may prevent small firms from
competing, thereby reducing competition and government revenues;

(c) the strategy of lessees will be to determine as efficiently as
possible which tract(s) to select for development, and the rest of the explor-
ation lease area may be explored only superficially;

M the initial lessee bears the risk that the development parcel
selected will have insufficient production potential to justify development
and that the government will not lease adjacent areas for many years (which
.risk will tend to reduce bids); and

(e) the government must consider the environmental and socio-economic
impacts of development that might occur anywhere within the exploratory area,
a far more difficult task than evaluating several small blocks.44

Because of the problems created by checkerboard leasing and surrender
requirements, it is recommended that the state not adopt either as standard
practice. However, it is conceivable that either approach could be used
flexibly to enhance the government's prospects in particular sales. While a
rigid checkboard pattern may not be preferable, neither is the offering of
large groups of contiguous blocks, and a middle ground in which small groups
of blocks are offered may be desirable. Large exploration leases should not
be offered, for reasons described earlier in this section, but surrender
provisions may have a place in small leases. For instance, where four blocks
cover a promising structure, the state might offer all four blocks under one
lease but with a.requirement that two of the blocks be surrendered later.
This,would provide companies with a little more incentive than if just two
blocks were offered, since the lessee would at least have the option of
selecting the more productive blocks.

Coordination of Sales with Adjacent Owners

Should lease sales be coordinated with those of adjacent owners? Since
the owner sharing the longest common boundary with North Carolina is the
federal government, this question is primarily concerned with OCS sales.
There are several factors to consider. If the state leases acreage adjacent
to the boundary at the same time as the federal government, industry planning
and exploration expenditures will be reduced and any field lying across the
boundary can be developed efficiently as a unit. By leasing state lands

44Many of these are drawn from Leland and Norgaard, "Outer Continental
Shelf Petroleum Leasing Policies," pp. 64-65.

85,

adjacent to federal leases the state can also avoid significant drainage
across the boundary, though the Outer Continental Shelf Lands Act contains a
provision to adequately compensate the state should this occur.45

With respect to the relative timing of the state and federal sales, there
are arguments to support several different options. If the state sale is held
before the federal one, all of the potential OCS bidders with their assembled
bonus moneys are available to participate, but they may hold back if the more
attractive prospects are on the OCS. if the state sale is held shortly after
the federal one, the state can take advantage of all the losing bidders who
now have large sums of bonus cash available and perhaps hopes of acquiring
more leases in the area. Which tactic is best probably depends on which
jurisdiction contains the best prospects, as companies will tend to harbor
their resources for bidding on these tracts. The state could also schedule
the sale of adjacent tracts 2-3 years after the federal sale, so as to take
advantage of the exploration results of the OCS lessees.

Both Alaska and Texas have made attempts to coordinate their programs
with the federal government. 'In both cases BLN/MMS has shown no interest in
reciprocating.

Coordination with an OCS sale may occasionally make sense, and in these
cases the state should give special consideration to applications for offer-
ings of adjacent tracts. Where state oil and gas resources are threatened
elsewhere by drainage, i.e., along the state's upland and lateral borders,
special consideration should also be given to leasing.

The Rate of Leasing

What is an appropriate rate of leasing? How quickly should eligible
areas be offered for lease? In addition to the previous two topics, both
of which involve elements of rate, there are several other relevant
considerations:

Government revenues. In The Leasing of Federal Lands for Fossil Fuels
Production, McDonald argues that the primary objective of government leasing
strategy should be for the government to capture a maximum of the present
value of the pure economic rent arising from minerals production on public
lands, where pure economic rent is the income which tends to accrue in
the long run, under conditions of perfect competition and the absence of

450CSLA �8(g), 43 U.S.C. 51337(g). Subsection (4) requires that federal
revenues from pools underlying the OCS/state boundary be placed in escrow
until an agreement is reached on "the fair and equitable disposition of such
revenues." A recent district court decision in Texas held that Texas was
entitled not only to the value of the hydrocarbons drained by federal lessees
from state lands, but also to a portion of the increase in value of federal
tracts resulting from leasing and exploration in state waters. if upheld on
appeal, the decision will give states more incentive to lease tracts adjacent
to the OCS. Wall Street Journal, Feb. 21, 1984,, p. 8.

externalities, to owners of raw natural resources.46 With regards to the rate
of leasing, such an approach leads him to the conclusion that rapid leasing
will tend to maximize the present value of the income received, though this
trend must be tempered by the possibility that accelerated leasing will, in
the short run, overwhelm the abilities of companies to explore and develop
lease tracts and will therefore depress rents.47 However, McDonald's focus is
on the federal program, -where approximately one billion acres are available on
the OCS. In North Carolina, where submerged lands total approximately two
million acres, it is unlikely that any decisions on leasing rates will have
any serious effect on the U.S. oil and gas industry as a whole, though they
might on the small segment of the industry willing to undertake the risks of
exploring in North Carolina.

Leland and Norgaard make several arguments for an active government role
in the rate decision and the spreading out of leasing over time.48 These are
based on (1) differences in the discount rates used by government and indus-
try, resulting in suboptimal investment and faster than optimal production;
(2) opposing reactions to risk between government and industry, also resulting
in faster than optimal production; (3) possible problems with industry insta-
bility (a tendency for boom-bust cycles); and (4) possibilities for improving
the generation of geological information and thereby reducing the risk for
both government and industry. This last point was partially addressed in the
discussion of checkerboarding and surrender requirements earlier in this
chapter; other options include contract exploration and exploration tax
credits. With regards to boom/bust cycles, while North Carolina is in no
position as a resource owner to influence these cycles (as Leland and Norgaard
suggest the federal government may be), the state should certainly be sensi-
tive to them in timing its sales to maximize revenues. The dramatic change in
market conditions for oil and gas rights between 1981 and 1982 is an excellent
example.49

Finally, any expectation of an increase in net revenues from a unit of
production (oil value minus costs) may make leasing delays preferable if the
private discount rate is greater than the social rate, as is likely.

46Stephen L. McDonald, The Leasing of Federal Lands for Fossil Fuels
Production (Baltimore: The Johns Hopkins Univ. Press for Resources for the.
Future, 1979), p. 2.
471bid., pp. 81-91.
48Leland and Norgaard, "Outer Continental Shelf Petroleum Leasing
Policies," pp. 52-58.
4911lustrative of this change are the results of OCS Sales 56 and RS-2
(in August 1981, and August 1982, respectively). Two tracts were bid on in
both sales. The high bids were, for tract 27: $3.324 million (Sale 56),
$1.713 million (RS-2); for tract 97: $746,000 (56), $150,000 (RS-2). In each
case the Sale 56 bids were rejected as insufficient, and the RS-2 bids were
accepted. No exploratory drilling took place in the region between the two
dates, and probably little, if any, geophysical exploration.

Economies of scale. Rapid leasing permits certain economies of scale, in
exploration, development, and production, that a slower pace of leasing may
not allow. To the extent that these can be foreseen.by companies prior to
leasing, a slow pace may depress rents; to the extent they cannot, slow
leasing will reduce company revenues. If all of the tracts overlying a
marginal field are not under lease at the same time, development may even be
precluded. Economies of scale may also produce economies in the amount of
disturbance. Where many blocks in an area are leased together, fewer facili-
ties may be needed to explore and develop the area than if the blocks were
-leased a few at a time over a period of many years.

Administration of the leasing program. The rate of lease offerings should be
such as to not overload the state bureaucracy charged with reviewing lease
proposals and overseeing active leases. This will be particularly crucial
early in the program when the bureaucracy is inexperienced and program pro-
cedures are still being refined. There should be an opportunity for the
bureaucracy to learn from its mistakes before large areas are leased and
committed to development.

Assimilative capacity of the natural and socioeconomic environments. In
determining the rate at which lands will be leased the state needs to consider
the assimilative capacity of the natural and socioeconomic environments for
leasing-induced change. Environmental impacts that are cumulative over space
but are temporary or diminish with time are important factors in the rate
decision. The pace of leasing should also allow for a.gradual and sustained
build-up of ancillary industries, where possible, and for adequate planning to
minimize social and economic disruption in coastal communities.

5.5 Pre-Sale Exploration

In order to prepare bids, companies must acquire information on the oil
and gas potential of the area in question. Two groups.of exploration methods
are typically used: geophysical methods (such as magnetic, gravity, and
seismic surveys) and geological methods (bottom sampling and shallow drilling
or coring).50 The conduct and interpretation of seismic surveys account for

50Another method'bf pre-sale exploration is the de ep stratigraphic test
well. These wells are drilled into the area of interest but usually away from
any potentially oil-and-gas bearing structure. They are drilled primarily for
geologic and engineering data which are used to evaluate the area's petroleum
potential and possible drilling problems, and are usually not completed even
if commercial quantities of oil or gas are found. As offshore wells are very
costly, companies usually fund the drilling collectively. Wells on the OCS
are known as Continental Offshore Stratigraphic Test (COST) Wells, and exten-
sive rules governing their drilling may be found at 30 CFR 251. Alaska's rules
at 11 AAC 96 are considerably simpler. it is unlikely that any deep strati-
graphic test wells would be drilled in North Carolina waters, as the type of
geological information obtained from these wells is available for the most
part from the many other wells already drilled in the coastal plain (Figure
4-1). Should any companies be interested, they would undoubtedly come to the

approximately 90 percent of exploration dollars.51

Seismic data may be obtained in several ways. Some of the larger oil'and
gas companies are equipped to conduct their own seismic work. More often a
company will hire a firm that specializes in seismic exploration, and when
several companies are interested in an area, they may band together to fund a
.1 group shoot." Sometimes a seismic firm will conduct surveys on a speculative
basis without a contract, hoping to sell the data later.

In the public waters of many states and on the OCS, a permit is required
to conduct exploration activities. The rationale for regulating such activi-
ties is that: (1) these activities may have adverse impacts on the natural
environment and may conflict with other uses of the area, particularly com-
mercial fishing; (2) permitting is necessary to ensure access to the data
later by the public agency; and (3) in some cases, government involvement may
facilitate information acquisition and cost sharing among companies (e.g., MMS
regulations on deep stratigraphic test drilling). The degree of regulation in
different programs is shown in Table 5-9.

NRCD has promulgated regulations on this subject under authority of the
oil and Gas Conservation Act.52 The rules require a permit for all seismic
work involving the use of explosives (powder, dynamite, nitroglycerin, etc.).
Every crew conducting seismic activities must be accompanied by a seismic
agent, a state employee who observes the operation and has authority to halt
any shooting in violation of the rules. Restrictions on the size and use of
explosives and the general conduct of operations are specified. A surety bond
and evidence of insurance must be provided, and there are certain reporting
requirements.

With respect to a submerged lands leasing program, these regulations are
deficient in two principal regards:53

1) Permits are required only for seismic surveys using explosives.
Other methods, including seismic surveys using air guns or sparkers, other
geophysical methods, and geological methods, are not covered (alth6ugh the
latter, which involve bottom disturbance, probably require permits under
CAMA). Such lack of regulation is appropriate for exploration on private
lands, where the state's concern is in preventing harm to neighboring proper-
ties and public resources. In public waters and marsh areas, however, other
exploration methods should be regulated as well, for several reasons. First,
non-explosive methods may have undesirable impacts. In several areas of the

state to request that the Conservation Act regulations guaranteeing well
record confidentiality for only 1-2 years (15 NCAC 5D .0008, .0010) be
changed; this would give the state time to review the situation and to
evaluate its regulatory authority under the Conservation Act and CAMA.
51Petroleum Extension Service, A Primer of Offshore Operations.(Austin,
TX: Petroleum Extension Service, University of Texas at Austin, 1976).

5215 NCAC 5C.

53The study did not attempt a technical assessment of these regulations.

Table 5-9

Regulation of Petroleum Exploration by Selected States
and the Federal Government

Permit required for petroleum exploration
in submerged lands using:
Must results
Seismic Other Geophysical Geological be submitted
Program Methods Methods Sampling u2on request?

Alabama X X X

Alaska X X

California X X X X

Louisiana X

Mississippi X X

Texas X X X X

U.S. OCS X X X X

North Carolina X**

*Authorized by law to require permit for this activity, but no permit
currently required.

**Seismic methods involving the use of explosives only.

country, conflicts between seismic firms and commercial fishermen have arisen
over interference between vessels and the possibility that seismic boomers may
harm fish larvae. These conflicts have reached a heated pitch in California.
Second, the state should simply be aware of who is evaluating public
resources. Finally, permits are necessary if the state is to require that
survey results be available for state use (see below).

2) The regulations do not req!!ire that survey results be made available
to the state. Current rules read that "the department on request will have
access to all records, but only to the extent necessary to determine

that all protective requirements have been complied with."54 The rationale
for expanding this requirement is that the state needs access to survey data
so that it can estimate the potential of each tract in order both to evaluate
whether bids are adequate and to weigh the petroleum potential against the
risks of development.

Five of the seven programs examined require that survey results be made
available to the permitting agency (Table 5-9). Texas rarely exercises its
option to acquire this information, as the General Land Office does not have
the manpower to interpret it; the state instead relies primarily on competi-
tion to ensure receipt of fair market value.55 On the other hand, before the
recent sale in Mississippi and the scheduled sale in California, neither
program had the authority to require disclosure of exploration results. Their
experiences with these sales convinced both states of the importance of such
disclosure, and both legislatures have recently enacted laws authorizing the
appropriate agencies to require disclosure of survey results.56

As the data may be bulky and expensive to reproduce, these regulations
only require disclosure upon request, and the permitting agency is responsible
for copying costs. It is important that such regulations require disclosure
not only of raw data, but also of results of any processing, analysis, and
interpretation.57

It is essential that disclosed exploration data be kept confidential, or
much of the incentive to explore will be lost. Under current North Carolina
law, however, the state is bound to release such information when requested to
do so. Chapter 132 of the General Statutes declares that all public records,
the definition of which would include disclosed exploration results, may be

5415 NCAC 5C .0021(b).

550f the two states that are not authorized to require disclosure,
Alabama relied on competition to generate bids of fair market value in its
1981 sale, while Louisiana uses comparable values and geologic information
from nearby wells to evaluate tract potential.
56For those particular sales, the two states approached their lack of
geological data very differently. Mississippi went into the sale "blind" and
relied on competition to assure receipt of fair market value. California,
partly out of need for information and partly in the belief that government
exploration is more efficient from a societal viewpoint, contracted for
seismic data and interpretation at a cost of $340,000. At one point the State
Lands Commission also contemplated an exploratory drilling program before the
sale whose cost would have run into the tens of millions of dollars, but later
abandoned the idea. of course, California already knew from adjacent OCS
sales that the tracts in question had very high resource potential, something
Mississippi did not.
57Examples of disclosure regulations may be found at 30 CFR 251.11-.14
(U.S.) and 11 AAC 96.210-.240 (Alaska).

"inspected and examined at reasonable times by any person. A
statutory exception will be needed to overcome this difficulty.58

Even where the government agrees to maintain results as confidential,
though, industry has objected strenuously to disclosure requirements.
Employees of government agencies and contractors may leak the results, or
results may be disclosed as employees change firms. Where companies perceive
that disclosure requirements increase the risk of leaks, such requirements
will create a disincentive to expensive exploration programsi Provisions that
attempt to counter these problems have been adopted by some or all of the
programs involved, and include:

(a) All such information is held confidential for a' certain length of
time (10 years is typical), and the state agrees to be liable for any
unauthorized use;

(b) The state may disclose the information to a third party (typically a
firm hired to process or analyze the data further), but the third party must
agree in writing not to disclose the information to anyone and not to acquire
an interest in the land in question. The contractor is held liable for unau-
thorized use and may be required to post bond, and the original permittee may
be given a chance to comment on the disclosure before the transfer occurs.

(c) The individual responsible for any unauthorized disclosure may be
not only liable'for civil damages but also subject to criminal charges.

Should North Carolina adopt disclosure requirements (and they are
recommended), such requirements should be accompanied by stringent procedures
and penalties to prevent unauthorized use.

However, it appears that NRCD does not currently have the authority to
require such disclosure. There is nothing in the oil and Gas Conservation Act
to indicate that disclosure of survey results would further the purposes of
the law. The state, therefore, has two options. The General Assembly could
pass legislation authorizing NRCD to require disclosure.59 This would be the

58Precedent for such an exception exists regarding disclosure of business
data by seafood licensees. N-C*G-S. �113-163(c).
59Examples of legislative authority for disclosure are Miss. Code Ann.
�29-7-3, Cal. Public Resources Code �6826, and 43 U.S.C. �1352(a). Comparable
legislation for North Carolina might look something like this:
(a) Any lessee or permittee conducting any exploration for, or
development or production of, oil or gas on state-owned lands, including tide
and submerged lands, shall, upon request, disclose to the Secretary of the
Department of Natural Resources and Community Development all data and
information (including processed, analyzed, and interpreted information)
obtained from such activity.
(b) Such data and information shall not be considered public records
within the meaning of Chapter 132 of the General Statutes. The Secretary
shall promulgate regulations prescribing the time periods and conditions which
shall be applicable to the release of such information.

simplest and most straightforward approach and is recommended. The law could
provide clear authority for the regulation of all exploratory activities as
well (see #1 above), which authority is somewhat tenuous under the oil and Gas
Conservation Act.60 A second option would be to require the submittal of all
geological and geophysical information in order to qualify for bidding. This
would avoid the necessity of going to the General Assembly, but is unsatis-
factory on two counts. Data would arrive within days of the sale, forcing the
state either to delay announcement of lease awards for weeks while the data
are studied, or to not use the data. The state would also lose the data of
firms that explored but decided not to participate in the sale.

5.6 Selection of Lessee

This subchapter will examine how a competitive bidding or auction system
might be constructed for a submerged lands leasing program. It is proposed
that such a system be designed to promote several objectives. They are,
first and foremost,

-to capture a major portion of the economic rent accruing from oil and
gas rights for the government (or, at least, to realize fair market
value);

(c) Whenever any employee of the State of North Carolina reveals infor-
mation in violation of the regulations promulgated pursuant to subsection (b)
of this section, the lessee or permittee who supplied this information to the
Secretary, and any person to whom such lessee or permittee has sold such
information under promise of confidentiality, may commence a civil action for
damages in a court of competent jurisdiction against the State of North
Carolina. The State will not raise as a defense any claim of soverign immun-
ity or any claim that the employee who revealed the privileged information
which is the basis of the suit was acting outside the scope of his employment
in revealing such information.
(d) Any person who makes unauthorized disclosure of such data and
information shall be guilty of a misdeameanor, and upon conviction be fined
not more than five thousand dollars ($5,000.00) or imprisoned not more than
one (1) year, or both.
60A separate section to provide this authority might read like this:
After Jan. 1, 1986, no person shall conduct any geological or geophysical
exploration for mineral resources (including, but not limited to, gravity,
magnetic, and seismic methods, core and test drilling, and various bottom
sampling techniques) in state-owned tide and submerged lands without having
first obtained a permit from the Department of Natural Resources and Community
Development. Such permit shall be issued only if the Secretary or his
designated representative determines that in accordance with rules issued by
the Secretary, (1) the exploration will not interfere with or endanger
operations under any lease issued pursuant to N.C. Gen. Stat. �146-8; and
(2) such exploration will not be unduly harmful to aquatic life, result in
pollution, create hazardous or unsafe conditions, unreasonably interfere with
other uses of the area, or disturb any site, structure, or object of
historical or archeological significance.

and secondarily,

-to transfer these rights to the most efficient firm, thereby minimizing
social costs;

-to promote competition and the entrance of relatively small firms
into the market;

-to minimize administrative costs;

-to promote a socially optimal rate of explorationP development, and
production; and

-to maintain the confidence of industry and the public with selection
criteria that are clearly written and fairly applied.61

Competition and Uncertainty

Studies and experience have shown that an auction system generally works
best in realizing the above objectives when two considerations are present:
a high degree of competition and a high degree of certainty regarding the
value of the item for sale.

Competition. A high degree of competition is though t to have two beneficial
effects: it increases the overall efficiency of the industry in exploring for
and developing new sources of oil and gas, and it results in higher government

61For comparison, in the conference report on the outer Continental Shelf
Lands Act Amendments of 1978 the House and Senate conferees declared it to be
their intention that in utilizing the new bidding alternatives a variety of
considerations should be taken into account, including, but not limited to:
(i) providing a fair return to the Federal Government; (ii) increasing com-
petition; (iii) assuring competent and safe operations; (iv) avoiding undue
speculation; (v) avoiding unnecessary delays in exploration, development, and
production; (vi) discovering and recovering oil and gas; (vii) developing new
oil and gas resources in an efficient and timely manner; and (viii) limiting
administrative burdens on government and industry. (U.S. House of Represen-
tatives, Conference Report on Outer Continental Shelf Lands Act Amendments of
1978, H. Rpt. 95-1474p 95th Cong., 2d session, 1978, p. 92.)
We have assumed receipt of fair market value to be one of the prime
objectives of the leasing program and have designed the program accordingly.
The state may very legitimately decide, however, that the recruitment of an
offshore oil and gas industry and an exploration program that is more rapid
and thorough than is likely to occur under existing market conditions are more
important objectives. The state may therefore wish to sacrifice some of the
fair market return to provide economic incentives for exploration and develop-
ment, particularly in the early days of the program when the financial risk is
very high. Such incentives can be provided in many ways, through public
funding of exploration, exploration tax incentives, public/private joint
ventures, or generous lease terms (including little or no royalty on an
initial amount of production, a longer primary term, etc.). An incentive
program need not include relaxed environmental protection.

revenues, based on the common assumption that greater competition causes
individual firms to bid more aggressively.62 How competitive is the bidding
for North Carolina leases likely to be? The question should be divided into

62This theory has an interesting wrinkle, commonly known as "the winner's
curse," that is particularly applicable to oil and gas lease sales. It can be
explained best by example. For a given sale, let us suppose that a company
bids what it expects each tract is worth, based on it's interpretations of
exploration data and other information. For any given tract, we know that the
company's bid will be either too high or too low, for uncertainties virtually
ensure that a company cannot correctly estimate a tract's exact worth. But
let us also suppose that, on average, the company's estimates are correct.
Let us further suppose that other companies behave similarly. The result will
be that during a sale company A will be more likely to win tracts whose worth
it has overestimated, and less likely to win tracts whose worth it has under-
estimated. Thus even though it's estimates are correct on average, the
company wins a biased set of tracts that are apt to turn out to be poor
investments. This is known as the "winner's curse." The mere act of winning
diminishes the win's value. Notice also that as competition increases, the
company will win fewer tracts, but the tracts it does win are apt to be those
whose worth it has most overestimated, for on average one misjudges the true
value of an item much worse when one comes out high against 50 other bidders
than against only 2 or 3. Capen, Clapp and Campbell have argued that in order
to ensure, on average, a specific rate of return under these circumstances,
the appropriate response to increased competition is to bid less. (E.C.
Capen, R.V. Clapp, and W.M. Campbell, "Competitive Bidding in High-Risk
Situation," J. Petroleum Tech. 23: 641-653, 1971.) Put another way., greater
competition diminishes the perceived value of winning because the mere act of
outbidding a large number of rivals strongly suggests that the firm has been
unduly optimistic. Any bid tendered, therefore, should reflect a company's
perceived value of a tract assuming it already knows that no other competitors
were prepared to bid higher. (James L. Smith, "Non-Agressive Bidding Behavior
and the 'Winner's Curse," Econ. inquiry 19:380-388, 1981.) Capen et al.
suggest that it is the winner's curse and the industry's failure to understand
it that are responsible for the industry's historically low rates of return on
offshore ventures in the Gulf.
How significant is the winner's curse in determining a firm's bidding
behavior, and what does this portend for attempts to increase competition at
lease sales? Smith used regression models to determine the factors controll-
ing bid size in seven lease sales between 1974 and 1976. (James L. Smith,
"Risk Aversion and Bidding Behavior for offshore Petroleum Leases,"
J. Industrial Econ. 30:251-269, 1982.) He found a clear, positive correla-
tion between competition and bid size, after controlling for a tract's
estimated worth. This may indicate, as Capen et al. suggest, that bidders
have been misinformed about their optimal bidding strategy, but with twenty
years of industry bidding experience in offshore sales there is a strong
presumption to the contrary. Smith's conclusion is that the typical response
to increased competition is not so extreme as to produce non-aggressive
behavior. Gilley and Karels point out that even if the optimal bid of a firm
decreases as competition increases, that does not imply that government
revenues will decrease, as there are more bids for the tract. (Otis W. Gilley
and Gordon V. Karels, "The Competitive Effect in Bonus Bidding: New
Evidence," Bell J. Econ. 12:637-648, 1981.)

two parts. First, how competitive is the offshore oil industry in general?
Jones, Mead, and Sorenson researched this question and concluded that it is
competitive and that a condition of free entry into the crude oil and gas
production industry prevails in the U.S.63 Their conclusion was based largely
on two findings: (1) that the internal rates of return before taxes from
offshore federal leases in the Gulf purchased between 1954 and 1962 was
estimated to average 9.5 percent, considerably below the performance of the
economy as a whole and hardly indicative of oligopolistic behavior,64 and
(2) that the concentration ratios for the industry, while substantial, were
still below those considered typical of oligopoly. As drilling in nearshore
waters is generally cheaper than on the OCS, it is likely that competition for
nearshore tracts (as in North Carolina) would be even keener. Secondly, how
competitive is North Carolina bidding apt to be? Prospects for oil and gas in
this state must presently be considered poor. Not surprisingly, the experi-
ence in offshore sales has been that competition has been weakest for the
least promising tracts. Tracts receiving only one bid are common; they
constituted 54 percent of the OCS tracts that were bid on in 1982.65 While
there are a number of factors that determine the level of competition, it must
be anticipated that, other things being equal, competition for North Carolina
tracts will be low.

The state should therefore consider what steps it can take to enhance
competition. There are two major ones:

1) Advertise the lease sale. This should be done in a timely manner so
that firms have a realistic amount of time to undertake exploration and
prepare a bid.

2) Minimize entry barriers to firms. Entry barriers can be either
explicit or implicit. Explicit barriers can include eligibilit criteria for
bidding (see below), rules on the acceptibility of joint bids,6K and rules
that disqualify bidders for immaterial mistakes in paperwork. Implicit
barriers generally bar entry to relatively small firms and are due to the high

63Russell 0. Jones, Walter J. Mead, and Philip E. Sorenson, "The Outer
Continental Shelf Lands Act Amendments of 1978," Nat. Res. J. 19: 885-908,
1979.

641n 1980, Mead and Sorenson extended their analysis to include leases
issued through 1969. The aggregate rate of return for this larger group of
tracts was estimated at 11.4% before taxes, up significantly from their
earlier estimate on the older tracts, but still low relative to other business
earnings. (Walter J. Mead and Philip E. Sorenson, "Competition and Perfor-
mance in OCS Oil and Gas Lease Sales and Lease Development, 1954-1969,"
Reston, Va., 1980, as cited in Minerals Management Service, "Report to
Congress on Fiscal Year 1982 Outer Continental Shelf Lease Sales and Evalua-
tion of Alternative Bidding Systems" (n.p., 1983), 59 pp.)
65Minerals Management Service, "Report to Congress," p. 54.

66The question of restricting the formation of joint ventures is a
controversial issue in offshore leasing policy. On the one hand, joint
ventures are comparable to temporary mergers and may have similar anti-

capital requirements and high risks that offshore development entails.67 Most
firms can easily acquire capital once a discovery is made, but large amounts
are often needed before a discovery for pre- and post-saleexploration and for

competitive effects. This is of particular concern in an industry already
suspected of oligopoly. (See Walter J. Mead, "The Competitive Significance of
Joint Ventures," Antitrust Bull. Fall 1967, 819-849.) Concern that joint
ventures among the majors would lead to reduced competition and an increase in-
their already sizable market share led the Department of Interior in September
1975 to ban joint bidding among firms that individually produce, on average
during a six-month period, more than 1.6 million barrels or barrel-equivalents
per day of crude oil, natural gas, and natural gas liquids. Congress enacted
the ban into law three months later in the Energy Policy and Conservation Act
(42 U.S.C. 6213(c); regulations now at 30 CFR 256.8-.44 and 10 CFR 376.301-
.303). The firms.on the most recent list of restricted joint bidders were
Chevron, Exxon, Mobil, Texaco, and Shell (48 Fed. Reg. 45318, Oct. 4, 1983).
The Justice Department also takes an active role in reviewing sale results for
their anti-competitive consequences and has, on occasion, proscribed further
ventures among firms not already on the list.
The Department of Interior has not conducted any empirical analyses to
evaluate the joint bidding ban. Several economists have doubted its value,
and no states have followed the federal lead. (See, for instance, Brian
Sullivan and Paul Kobrin, "The Joint Bidding Ban: Pro- and Anti-Competitive
Theories of Joint Bidding in OCS Lease Sales," Research Paper #010, American
Petroleum Institute, Washington, D.C., 1978, 55 pp., and the unpublished Spann
and Erickson study reported in McDonald, The Leasing of Federal Lands for
Fossil Fuels Production, pp. 106-107.) There is, however, widespread agreement
that joint bidding has a positive effect on competition.with regards to other
firms. Joint ventures allow these companies to compete with the majors for
the more attractive prospects by sharing costs and risk. Greater competition,
in turn, results in higher government revenues. Dougherty and Lorenz examined
OCS lease sales between 1954 and 1974 and found that joint bidders tended to
bid on the more sought-after (and apparently more valuable) tracts and tended
to bid higher, on average, than their solo-bidding competitors. (E.L.
Dougherty and J. Lorenz, "Statistical Analyses of Bids for Federal Offshore
Leases," J. Petroleum Tech. 28:1377-1388, 1976.) In addition Smith's regres-
sion models of OCS sale results suggest that joint bids tend to be greater in
magnitude than those that would be tendered by individual consortium members,
though he noted that this might not apply to the seven major firms, who appear
to have reached a position of risk neutrality. (Smith, "Risk Aversion and
Bidding Behavior for Offshore Petroleum Leases.")
67The basic rationale in lowering such barriers is that where costs and
risks are high only a few firms can afford to bid, and this lower level of
competition results in lower governmentrevenues and more opportunity for
manipulation of the auction. While lower barriers will hopefully improve
market performance, they should not be lowered so much that firms without the
financial capability to meet the lessee's environmental, safety, and other
responsibilities become competitive. In other words, while it may be laudable
from a free-market and revenue standpoint to structure the auction so that
small firms can compete with the big guys, there is a limit to how small a
firm the state will want drilling for oil in its submerged lands.

payments to government, primarily bonuses.68 These capital requirements may
be lowered:

(a) by tailoring the size of at least some tracts to the potential of the
area, so that bonus bids will not be excessively high. Alaska tries
to offer tracts in a range of sizes from one to nine square miles, so
as to encourage participation by smaller firms.

(b) by using bidding systems with low front-end payments. Bonuses can be
spread out over time,69 or emphasis shifted to royalties and profit
sharing where.payments are contingent on discoveries.

The traditional hypothesis of decreasing absolute risk aversion states
that the premium required to induce a firm to accept a specific risk is
inversely related to the size of the firm.70 Therefore the larger the risk,
the less likely that small firms will be competitive with larger ones. Smith
found evidence of this in OCS bidding, where, after (hopefully) controlling
for tract value and the degree of competition, he found that large firms
tended to bid more than smaller ones, which he felt was best explained in
terms of differing responses to risk.71 There are two ways in which the state
can reduce the risk for individual firms and thereby improve competition: by
lowering the risk associated with individual tracts (discussed below under
Uncertainty), and by permitting and encouraging diversification of risk. The
latter may be accomplished by using bidding systems that transfer some of the
risk to the government (substantial royalty and profit share rates make a
substantial portion of compensation contingent on discovery of oil or gas),
and by allowing the formation of joint ventures.

Uncertainty. If private firms are generally risk averse, then the higher the
risk or uncertainty associated with an individual tract, the greater the risk
premium will be. High risks therefore result in lower bids and lower govern-
ment revenues.

681n their study of Gulf tracts leased between 1954 and 1969, Mead and
Sorenson found that leases attracting the highest bids tended to be the most
productive, but that companies bid this productivity away so that the rate of
return on these tracts was less, on average, than tracts purchased with
smaller bonuses. This suggests that during this period high bonuses did not
affect competition in a way that reduced government revenues. ( Mead and
Sorenson, "Competition and Performance in OCS Oil and Gas Lease Sales.")

69The Outer Continental Shelf Lands Act authorizes Interior to defer
bonus payments up to five years (43 U.S.C. �1337(a)(2)). Logue, Sweeney and
Willett suggest even easier terms for some leases: a payment schedule that
does not require any payment for up to five years, and payment after that in
annual installments over a 10-20 year period, guaranteed by a bond or
insurance. (Dennis E. Logue, Richard J. Sweeney, and Thomas D. Willett,
"Optimal Leasing Policy for the Development of Outer Continental Shelf Hydro-
carbon Resources," Land Econ. 51:191@207, 1975.)

70Smith, "Risk Aversion and Bidding Behavior," p. 252.

71Ibid., p. 258.

Firms bidding on offshore leases face three types of uncertainty:

-the size of the petroleum deposit;

-the cost of exploration and development; and
-future petroleum prices.72

There is very little North Carolina can do about the third item, but the
state does have several options for reducing uncertainty associated with the
first two. Changes could be made in how exploration is conducted to provide
better information at less cost, through government funding or facilitation
of cost-sharing among companies. The state should try to minimize what Dam
calls the risk of state repudiation,73 the possibility that the state will
later try to alter the effective terms of the agreement through legislation,
such as passage of a substantial severance tax. The state cannot eliminate
this risk, but it can reduce the perceived risk by reviewing such matters
thoroughly and making recommended changes before the lease sale. Most
importantly, the state can minimize the uncertainty associated with adminis-
trative and regulatory costs,by making a concerted effort before the sale to
identify the principal restrictions and conditions that will be attached to
permits. The betterthe track record the state establishes in not imposing
major, unexpected regulatory costs after the lease sale, the higher the bids
will be in future sales. The efforts of states such as Texas and Alaska to
notify bidders of likely environmental restrictions and permit conditions were
noted earlier in Section 5.2.

Given these basic considerations about competition and uncertainty, the
remainder of this subchapter will examine a number of specific sales policy
issues:

-What eligibility criteria for bidding should be established?

-Should the sale be conducted by oral auction or sealed bid?

-What should the bidding variable and the fixed compensation terms
be?

-Should a market based refusal price be stipulated?

-Should the bids be publicly opened and announced?

-How should the sale results be evaluated to determine whether and
-with whom the state should execute a lease?

Two final topics that are mostly mechanical will be reviewed briefly: bidding
mechanics and execution of the lease.

72Leland and Norgaard, "Outer Continental Shelf Petroleum Leasing
Policies," p. 25.
73Dam, Oil Resources, pp. 175 ff.

Bidder Eligibility Criteria

Eligibility criteria for bidders can be used to pursue a variety of
objectives, and three of the seven major offshore programs utilize them to
some extent (Table 5-10). While the other four programs have no explicit
criteria, other state laws may serve the same purpose. Any company desiring
to bid on Louisiana leases, for instance, must be registered to do business in
that state.

The possible use of a criterion requiring a good environmental record was
discussed in Section 5.3. Criteria used by other leasing programs include:

1) Due diligence. The Outer Continental Shelf Lands Act Amendments of
1978 state that: "No bid for a lease may be submitted if the Secretary finds,
after notice and hearing, that the bidder is not meeting due diligence
requirements on other leases."74 This provision reflects concerns raised
several times after the 1973 oil embargo that some companies were withholding
production to create an artificial scarcity. A study at Interior led to the
cancellation of two leases in the Gulf in June of 1977 for lack of drilling
activity, and a study by the National Academy of Sciences and National Academy
of Engineering concluded that in at least one of the six gas fields reviewed,
accelerated production of natural gas was warranted.75 Proponents of the due

Table 5-10

Requirements for Bidder Eligibility

Due Legal Joint Acreage Financial Equal
Program Diligence Status Bidding Limit Ability Opportunity

Alabama

Alaska X X

California X X

Louisiana

Mississippi

Texas

U.S. X X X X

74Codified at 43 U.S.C. �1337(d).

75Robert B. Krueger and Louis H. Singer, "An Analysis of the Outer
Continental Shelf Lands Act Amendments of 1978," Nat. Res. J. 19:909-927,
1979.

100

diligence clause claim that the federal government, as a landowner, should
have the right to reject prospective lessees who are not meeting their obliga-
tions elsewhere, in the interests of maximum revenue and efficient management.
No states have followed suit.

2) Legal status. The U.S., Alaska, and California all require that
bidders qualify in-one of several legal categories.76 OCS leases, for
instance, can only be held by U.S. citizens, nationals, permanent resident
aliens, corporations organized under federal, state, or territorial laws, and
associations of the above. The lists of permissible categories in Alaska and
California are slightly different; both of those states, for instance, also
include citizens of other countries which grant similar privileges to U.S.
citizens.

3) Joint bidding. The U.S. has banned joint bidding among certain
majors to promote competition.77

4) Acreage limit. Alaska limits the lease holdings of any person or
corporation to 500 000 acres of tide and submerged lands and 500,000 acres of
other state lands.18

5) Financial ability. California requires the top three bidders for
each tract to submit a financial statement demonstrating the bidder's ability
to undertake the operations and obligations of the lease. Other programs rely
on the various bonds required of the lessee to protect the state against
financially unfit firms.

6) Equal opportunity. Bidders at OCS lease sales are required to show.
compliance by the firm with the e ual opportunity/affirmative action regula,-
tions of the Department of LaborN

California and the U.S. require that paperwork establishing a bidder's
eligibility be submitted no later than at the time of the sale itself.
Alaska, on the other hand, requires prospective bidders to "pre-qualify" by
establishing their eligibility at least the day before the sale. This allows
the state at the time of the sale to determine immediately whether a high
bidder is qualified, and if so, to return the deposit checks of the unsuccess-
ful bidders. Should North Carolina choose to establish eligibility criteria,
it-is recommended that bidders be required to establish their eligibility
before the sale.

7630 CFR 256.35(b); 11 AAC (Alaska Administrative Code) 82.200; Calif.
Public Res. Code �6801.

77See note 63, above.

78Alaska Stat. �38.05-140(c); 11 AAC 82.300-.310.

7941 CFR �60-1 and Executive Orders 11246 and 11375.

101

Sealed Bid vs. Oral Auction

Walter Mead's 1967 paper on oral versus sealed bidding in natural
resource auctions is the definitive discussion on the subject, and much of
what follows is based on his exposition.80

The key characteristics of oral bidding are that the bidders know who
their competitors are during the course of the sale, and that a bidder has an
opportunity to respond to competitors' bids with a higher one of his own.
These traits lead to several undesirable characteristics of oral auctions.
First, they facilitate such practices as collusion (by allowing conspirators
to police the agreement and react if someone breaks it), implicit bargaining
(the use of bids to signal to others a firm's intentions), preclusive bidding
(the use of a high initial bid to make entry expensive or impossible for
another), and punitive bidding (the punishment of a participant for some past
transgression by bidding up the price of items of special interests to the
offender).81 Where there is only one bidder, he will win the tract at just
above the announced reservation price. if that price is difficult to set
realistically, as it is with oil and gas rights, the bidder may get a bargain.
With oil and gas properties there is also the "free rider" problem. Where
large exploration expenses are necessary before a sale, a bidder can avoid
these by bidding Incrementally over other bidders on the assumption that
others will not bid more than what their exploration results indicate the
tract is worth. Finally, oral auctions require the presence of someone
authorized to make immediate, sometimes major decisions.

In general these problems are most severe when the level of competition
is low. Changes in the conduct of oral auctions have been suggested that
might alleviate some of these problems. These include electronic oral bid-
ding, in which bids are submitted electronically from different locations with
the identities.of bidders kept secret, and the use of sealed government
reservation prices that are opened only after the bidding is closed.82

On the other hand, there are two principal advantages of oral bidding.
The individual bidder has the opportunity to react to other bids and increase
his own where he has an additional incentive to win. This is particularly
important in industries structured like the timber industry,- where an operator
generally has a large, fixed investment in a mill and only the timber within a
short radius available to him because of high transportation costs. In these
cases, it is important that an operator have control over whether he wins or
loses a particular tract, as a failure to win enough tracts nearby may mean

80Walter J. Mead, "Natural Resource Disposal Policy -- Oral Auction
Versus Sealed Bids," Nat. Res. J. 7:194-224, 1967.
81Preclusive and punitive bidding and the possibility of emotional
excesses during bidding Mead cites as disadvantages of oral auctions. Though
they result in higher government revenues, Mead contends that they result in
lower long-term revenues by reducing competition and/or by damaging a firm's
financial ability to develop a tract.
82McDonald, Leasing of Federal Lands, p. 78; Mead, "Natural Resource
Disposal Policy," p. 201.

102

his ruin. This is not true of the oil and gas industry. Secondly, bidders
can adjust their bidding on subsequent tracts based on whether they have
already won enough or whether they still have capital and facilities available
to handle more.

Sealed bidding avoids many of the problems of oral auctions. Bidders do
not know who their competitors will be, and they have only one chance to bid,
,with no opportunity to respond. Under these circumstances, a bidder is
strongly motivated to enter a bid closely approximating his valuation of a
tract, suitably discounted for risk. Collusion and implicit bargaining are
more difficult, as there is no opportunity to send signals or police an agree-
ment during the course of the auction. Such unfair practices as preclusive
and punitive bidding are also restrained. In the single bidder situation, the
government may still get close to a competitive price because of the bidder's
uncertainty about the number of his competitors. The free rider problem is
completely eliminated.

These advantages may have been overstated, because particularly in sub-
merged lands leasing, bidders are often well informed about the number of
potential bidders as a result of pre-sale exploration. It has already been
noted that bids are often adjusted for the expected degree of competition.
Bidders may also adjust them for the bidding strategies of their expected
competitors, as determined from previous sales.

The major disadvantage of sealed bidding is that in multi-tract sales, a
bidder must choose between bidding on enough tracts so that the fraction it
expects to win will match the firm's resources, in which case it runs a danger
of becoming over-committed, or else bidding on fewer tracts to be safe, in
which case it will probably win fewer than it could develop, and the overall
level of competition will be reduced in both the short- and long-term.83 This
is primarily a disadvantage of bonus bidding, and with royalty and profit-
share bidding financial constraints are presumably not as severe. The
difficulty may be partially resolved with sequential bidding, in which,
after the bids on one tract are opened and announced, bidders are given the
opportunity to submit bids for the next tract.84

83McDonald, Leasing of Federal Lands, p. 81.
841bid., p. 108. The order of bid opening might be determined by the
number of bids submitted, a vote of bidders, random selection, or other means.
To minimize possibilities for collusion, signalling, and similar practices,
just the amount of the winning bid could be announced following each round, or
each bidder could even be informed privately whether he had won or lost. The
disadvantages of sequential bidding are that the process of awarding leases
becomes cumbersome and time-consuming, those attending lease sales must have
the authority to make major decisions rapidly or come equipped with complex
contingency plans, and it may be difficult to accompany each bid with a
deposit in the required form.
McDonald contends that sequential bidding would increase the average number
of bids per tract and the level of the average winning bid. California has
used sequential bidding in pre-Santa Barbara sales. The U.S. Department of
Energy proposed an experimental sequential bidding procedure for OCS sales (44
Fed. Reg. 52842, 1979), but the procedure never received fina 1 approval.

103

The conclusion to be drawn from Mead's analysis is that for a sale in
which competition may be weak, where a realistic refusal price is difficult to
set, where firms do not have major stakes in acquiring specific items, and
where free riders may be a problem (all of which apply to oil and gas lease
sales in North Carolina), sealed bids are preferable. The oil and gas
industry has stated its preference for sealed bids.85 Sealed bidding is used
in all seven of the major offshore leasing programs examined and is statu-
torily required in five of them. It is recommended for use in North Carolina
as well, possibly modified to include a sequential bidding procedure.

Bidding Variable and Fixed Terms

An issue that has received a great deal of attention from policy-makers
and economists is the question of optimal bidding systems. it is clear that
under the assumptions of perfect competition,.perfect information and fore-
sight, no tax distortions, and perfect capital markets, the standard practice
of cash bonus bidding would work exceptionally well and there would be no
need to consider alternatives. The bonus offered would be the present value
of a tract's net cash flow, which is the economic rent a bidding system should
ideally capture.86

.However, many of these assumptions do not hold because of the nature of
petroleum discovery, the petroleum market, and the structure and function of
the petroleum industry. As a result, several different bidding systems have
been examined and tested for their performance in terms of the objectives
listed earlier. The advantages and disadvantages of the three major bidding
variables will be examined first, assuming in each case the other fixed terms
are negligible. Other options and combinations will then be considered.87

Bonus Bidding. Relatively pure bonus bidding has several key characteristics.
By requiring a front-end payment regardless of future discoveries, it places
virtually all of the risk on the lessee. The uncertainty associated with
petroleum discovery is apt to depress the amount of bonus offered to a greater
extent than would occur if a contingent payment such as a royalty or profit-
share comprised the major portion of compensation. The large bonuses required
for promising tracts will also tend to operate as barriers to entry by smaller
firms, thereby restraining competition.

The great advantage of bonus bidding is that the bonus, once paid,
becomes a sunk cost that is irrelevant to future exploration, development and
production decisions. (A slight exception is that on surrendered tracts the

85Mead, "Natural Resource Disposal Policy," p. 219.

86Robert J. Kalter, Wallace E. Tyner, and Daniel W. Hughes, Alternative
Energy Leasing Strategies and Schedules for the Outer Continental Shelf,
Cornell Univ. Ag. Expt. Sta. Research Rpt. 75-33 (Ithaca, N.Y.: Cornell
Univ., 1975) (NTIS: PB 253315), p. 47; McDonald, Leasing of Federal Lands.
87Much of the following discussion relies heavily on McDonald, Leasing of
Federal Lands, except where noted.

104

bonus can be written off immediately, thereby biasing the decision in favor of
abandonment of marginal properties.) The lack of royalty or profit-share
payments gives the operator the greatest incentive for efficiency.

Royalty Bidding. Royalty bidding, on the other hand, results in a sharing of
risk with the government. Exploration costs are risked solely by the opera-
tor, but no compensation is due the government unless petroleum is found and
produced. The reduced risk and lower cash requirements not only lower the
entry barriers to firms, but also lower the risk premiums, so that firms will
tend to bid a higherproportion of the expected economic rent.

There are several disadvantages to royalty bidding. Since the royalty
payment is part of operating costs, properties that would turn a marginal pro-
fit without a royalty may be unprofitable with one. The result is that fields
may be abandoned early (as production declines and costs rise) or not
developed at all, with a net loss to society. Most leasing programs have the
authority to lower royalty rates so as to prevent early abandonment, but if
this is done regularly the system will break down, as firms will bid whatever
is needed to win a tract and rely on the public agency to lower the royalty
later to make production profitable. There is also a danger with royalty
bidding that some firms will bid very high with hopes of making a major find,
and then abandon the tract if minimal exploration suggests such a find is
unlikely. Finally, different royalties on adjacent tracts make unit operation
difficult, promote drainage of reserves from high to low royalty tracts, and
may encourage inefficient drilling and platform locations.88

Profit-share bidding. As explained in Section 5.1, under a profit-share
agreement the lessee pays the lessor a fixed percentage of the profits
realized on the lease. These profits may be calculated in three ways:
(1) The IRS definition may be used, in which profits are gross revenues minus
operating costs and capital consumption allowances. Under current IRS rules,
some exploration and development costs may be expensed currently, while others
must be depreciated. (2) Under a fixed-capital recovery plan, the lessor
shares in gross revenues minus operating costs, but only after the total
capital investment, multiplied by some factor usually greater than 1, has been
recovered by the lessee from operating profits. (3) With an annuity capital
recovery system, total capital outlays with accumulated interest are converted
when production begins into an annuity with a specified interest rate and
term, and the amount of the annual annuity is subtracted from each year's
operating profits, with the remainder serving as the profit-share base. It
should be evident that the fixed-capital recovery plan provides the lessee
with the best assurance of a certain return on investment, with the annuity
system next and the IRS system last. The fixed-capital recovery system is the
most common in use.

Profit-share bidding possess es many of the characteristics of royalty
bidding. With no front-end payment and a shift of some risk to the govern-
ment, entry barriers and risk premiums are lower than with bonus bidding,
resulting in more competition and capture of a higher proportion of economic

88Minerals Management Service, "Report to Congress, 1982," p. 22.

105

rent by the government. Also like royalty bidding, profit-sharing may result
in early abandonment or no development at all of marginal properties. Profit-
shares are superior to royalties in this respect, as costs are at least taken
into account; among profit-share methods the annuity and fixed-capital systems
rank highest, in that these make some provision for a normal return on invest-
ment. However, these same characteristics make excessive bidding even more
likely with profit-sharing. The incentive for efficiency is also considerable
reduced. on the other hand, -with government given a stake in lease profits,
regulatory costs may be restrained.

The major practical difficulty with profit-sharing, regardless of whether
it is a fixed term or bidding variable, is the government oversight required.
Since expenses charged to a lease cost the lessee only the fraction that is
it's profit-share, the lessee is motivated to charge as many expenses as
possible to the lease. The lessor, therefore, must monitor the lessee's
financial records and establish detailed rules for allowable expenses. These
rules run to 14 pages in the Code of Federal Regulations and to 39 pages in
the most recent California lease.

Combinations. In fact, it is rare that one of these terms is used as the sole
method of compensation. In most bidding schemes, one type of compensation is
selected for the bidding variable, and one or both of the other two, as well
as a delay rental, are included as fixed terms and announced before the sale.
The resulting bidding systems tend to have some of the advantages and
disadvantages of each of the methods included. A few of the more common
bidding systems are discussed below.

(1) Bonus bidding with a substantial fixed royalty. As seen earlier,
bonus bidding (with no royalty) is superior to royalty bidding (with no bonus)
with respect to its effect on the margin of development and production, but
inferior because of higher capital requirements and risk. The best option may
be somewhere in between, perhaps near what has been the standard bidding
system for many years, bonus bidding with a fixed royalty of 1/8 or 1/6.89
One problem with a fixed royalty in this situation is that it is difficult to
set it high enough to transfer a large portion of the risk to the government
without setting it so high that the margin of development is seriously
affected.90

(2) Bonus bidding with a substantial fixed profit-share. This system is
similar to the preceding one. It is slightly superior with regard to its
effect on the margin of development and production, but inferior with regard
to administrative cost.

(3) Bonus bidding with a sliding scale royalty. A sliding scale royalty
is one in which the royalty rate during any period varies directly with the
value or amount of production in that period. The advantage of sliding scale
royalties over fixed rates is that the royalty can be set high for very
productive tracts, yet low enough on marginal tracts so as to not seriously

89McDonald, Leasing of Federal Lands, p. 102.
90Kalter and others, Alternative Energy Leasing Strategies, p. 49.

106

affect development or abandonment decisions. In frontier areas like North
Carolina sliding scale royalties allow low potential tracts to be leased for
modest sums while protecting the state against a give-away if a substantial
find is made. The major disadvantage of sliding-scale royalties is that they
are not neutral with respect to decisions on development and the time distri-
bution of production, and may induce less than socially optimal behavior
regarding the rate of extraction.91

(4) Royalty bidding with a substantial fixed bonus. The major question
regarding use of this system is whether the bonus can be set high enough to
prevent excessive royalty bids yet not so high as to bar entry to the smaller
firms that royalty bidding is intended to attract. The federal government has
experimented with royalty bidding in two OCS sales. In the first, OCS Sale 36
in October 1974 'ten tracts were offered under royalty bidding with the bonus
set at a modest $25/acre. Analysis of the results led Interior to conclude
that tracts with royalty bidding had attracted more bidders than similar
tracts offered under bonus bidding, but that royalty bidding did not appear to
increase the relative success of independent operators.92 For the eight
tracts that received royalty bids, the U.S. Geological Survey estimated that
the royalty rates that could be expected to generate a normal rate of return
were in the neighborhood of 20%. The winning bids in fact ranged from 51.8%
to 82.2%. USGS?s analysis estimated that losses in the present value of
resources as a result of early abandonment, nondevelopment,'and slowdowns in
exploration induced by these high royalty rates amounted to approximately
50%.93

91There are several types of sliding scales in use. The Minerals
Management Service uses a scale of the form

Rj = b[ln(Vj/S)l

where Rj = royalty percentage in quarter j,
Vj = inflation-adjusted production value ($million) in quarter J,
b = a sliding scale coefficient that determines the slope of the
curve, and
S = a scale factor that sets the initial point at which the
royalty rate exceeds the minimum.

Such a scale is sensitive to increases in both the real value of the resource
and the volume of production. Non-linear scales are preferred because they
can ameliorate the incentive created by linear forms to slow the rate of
production.
MMS has been using sliding scale royalties increasingly as an alternative
to the fixed royalty system. The agency has examined and experimented.with
several different scales in its attempts to find ones that substantially lower
capital requirements (i.e., bonus bids) with minimal effect on investment and
production decisions. (Minerals Management Service, "Report to Congress,
1982," pp. 24-25.)
92McDonald, Leasing of Federal Lands, p. 100.

93Minerals Management Service, "Report to Congress, 1982," p. 22.

107

The second royalty bidding experiment was conducted in the Cook Inlet
Sale of 1977. Bonuses on these tracts were set substantially higher, and as a
result of this and the high costs of Alaskan OCS development, winning royalty
bids averaged about 40%. Such bids were still deemed to be high relative to
the costs of production, and were estimated to have resulted in losses in the
present value of resources of 10-20% above those induced by a traditionally
low fixed royalty. Moreover, sale results did not indicate any significant
difference in the levels of competition between bonus and royalty bid
tracts.94

(5) Profit-share bidding with a substantial fixed bonus. This is similar
to the preceding system and will tend to have similar problems. The likeli-
hood of premature abandonment is reduced, but the incentive to bid excessively
high is even greater.

There are a variety of other schemes that have been proposed, a few of
which have been tried but none of which have caught on, at least in this
country. These include rental bidding, bonus or royalty bidding with high
delay rentals, royalty bidding on a multiple of a sliding scale, work commit-
ment bidding,,working interest bidding, bonus bidding using installment pay-
ments with a forgiveness option, and others. Several publications discuss
these options.95.

A different type of system from those discussed so far is dual bidding,
in which bidding is conducted on two or more bid variables simultaneously.
Alabama, for instance, required that bids be submitted on both the cash bonus
and royalty for tracts offered in its 1981 offshore sale. Louisiana permits
bidding on the cash bonus, royalty, and rental simultaneously, and also allows
other obligations (e.g., work commitment, depth limitations) to be included
and considered. On the other hand, some programs are statutorily forbidden
from using dual bidding.

The advantage of dual bidding, as advanced by its proponents, is that it
provides the state with additional flexibility in obtaining the offer most
advantageous to the state. The obvious disadvantage is that bid evaluation is
made more difficult. Industry is firmly opposed to it as it involves the
additional task of guessing what administrators are looking for in a bid.
This additional uncertainty may undermine general confidence in the selection
process and may lead some firms to decide that bidding is not worth the cost
involved. It is recommended that North Carolina join the majority of states
in not using dual bidding.

There are studies galore on the advantages and disadvantages of different
leasing systems, each based on its own particular models and-with its own sets
of assumptions and recommendations. There is also a wealth of experience to
be culled from other leasing programs (Table 5-11). At this point a firm
recommendation for a single bidding system to be used in North Carolina cannot
.be made, as any system should be tailored to the particular circumstances

941bi.d., pp. 22-23.
95See McDonald, Leasing of Federal Lands, and Kalter and others,
Alternative Energy Leasing Strategies.

108

Table 5-11. Bidding Systems Used by Selected Leasing Programs, 1970-1983

Bidding System Alabama Alaska California Louisiana Mississippi Texas U.S.

Bonus bidding with X X X X
fixed royalty
X
Bonus bidding with X
sliding scale royalty
X
Bonus bidding with
fixed net profit
share

Bonus bidding with X
fixed royalty and
net profit share
X X
Royalty bidding with X
fixed bonus

Net profit share X*
bidding with fixed
bonus

Net profit share X
bidding with fixed
bonus and royalty

Dual bidding X X

*Point Conception leases were to be awarded on the high net profit share bid with no official bonus or
royalty. The first three years' rentals on each lease, however, were very high and were due regardless of
circumstances, making then in effect a fixed bonus payablew in three annual installments.

surrounding the leases to be sold. Some of the major considerations that
should enter into this decision have been discussed above. Based on these
considerations and various studies and experience, however, two general
recommendations are ventured for initial lease offerings in this state.
First, net-profit-share payments, despite a number of advantages, are
administratively too difficult and cumbersome to be handled well by a fledg-
ling and probably part-time program, and should not be included in any lease.
Second, a sliding scale royalty has much to recommend it and should be
considered as a serious alternative to the traditional fixed royalty with
bonus bidding.

Finally, a word should be said about severance taxes. Severance taxes
are taxes imposed on the removal of natural resources (oil and gas, timber,
coal, etc.) and levied on the basis of the quantity or value removed. Twenty-

109

seven states currently have some form of severance tax on oil and/or gas,
ranging as high as 15 percent for some types of oil wells in Alaska.96 In
North Carolina the Department of Natural Resouirces and Community Development
is currently authorized to levy a tax of $.005 per barrel of oil and $.0005
per 1000 cubic feet of gas produced to pay the administrative costs of the oil
and Gas Conservation Act.97 More substantial rates have been a topic of
discussion for several years.

severance taxes function essentially like royalties, and for production
on state-owned land merely replace an equal amount of royalties that the state
could otherwise extract from the lessees. Their major difference is that they
also produce state revenues from production on private lands. The basic
theory of severance taxes is that the current and future costs of resource
development, including asset replacement costs, should be borne by the users
of that resource. In keeping with that notion, several states place severance
tax revenues in permanent trust funds, with the income used for a variety of
purposes, including economic development energy impact mitigation, education,
and as a supplement to the general fund.18

Severance tax debates make oil and gas operators understandably jittery,
since a severance tax can be a major cost of production and can be imposed
unilaterally, and at any time, by the state. In designing an oil and gas
program the state should carefully consider whether additional severance taxes
are appropriate, and should make an attempt to review the matter and settle
the question for the foreseeable future before any sales are held.

Market-Based Refusal Price

In some natural resource auctions, a market-based refusal price is
announced before the sale to inform bidders of the minimum amount the public
agency is willing to accept, thereby setting a floor for bidding (particularly
in oral auctions) and saving some firms the time and effort of preparing bids.
Refusal prices are most common in oral auctions of timber.99

There are two reasons why refusal prices should not be announced before a
sealed bid oil and gas sale. First, the problems of establishing a realistic
refusal price before the sale are formidable. As noted before, accurate
appraisal of oil and gas properties without exploratory drilling is very
difficult. Often compounding the problem is the public agency's lack of
geologic information or the manpower and time to interpret it. In many cases

96Earl E. Starch, Taxation, Mining, and the Severance Tax, Bureau of
Mines Information Circular 8788 (Washington, D.C.: Bureau of Mines, U.S.
Department of the Interior, 1979), pp. 50-54.

97N.C. Gen. Stat. �113-387.

98Richard V. Watson, "The Use of Royalty and Severance Tax Revenues,"
Legislative Finance Paper 10, National Conference of State Legislatures Fiscal
Affairs Program, Denver, Colorado, 1982.
99Mead, "Natural Resource Disposal Policy," pp. 200-201.

110

government even uses the bidding results themselves to help determine whether
high bids are adequate. Secondly, even if a realistic refusal price could be
determined before a sale, by keeping it secret the public agency essentially
becomes a bidding participant, effectively increasing competition and the
general level of bids, particularly in low interest areas.100

While several of the major offshore programs stipulate minimum bids, all
reserve the right to reject any bids deemed insufficient. The stipulated
minimum bids in these cases tend to be standard (in some cases statutory)
values and serve to place a floor under bidding without removing the
uncertainty surrounding acceptance of the high bid. Whether such stipulated
minimums have any utility is not known. It is recommended that North
Carolina, like other offshore programs, not announce refusal prices before the
sale; the state may wish to experiment with announced minimum bids.

Public Announcement of Bids

In the seven offshore leasing programs examined, all bids are publicly
announced at the sale. The advantages of bid disclosure are that it rein-
forces public confidence in competitive bidding, allows public oversight, and
provides an indication of how competitive the bidding is and how government
acceptance or refusal relates to bid numbers and amounts.

However, several arguments can be advanced in favor of keeping all but
the winning bids confidential. Public disclosure allows companies to analyze
the bidding patterns of their competitors and adjust their future bids
accordingly, most probably to the detriment of government receipts.101 In
addition, if bids are not announced, the amount by which the winning bid
exceeds the second highest bid, known as money "left on the table," will not
be known. Mead notes that "the real attitude of land men toward 'leaving
money on the table' is one of considerable embarrassment leading one to
remark, 'I'd rather lose a lease than leave money on the table."'102 If this
attitude is prevalent, public disclosure may result in lower bids. Even if
losing bids are not announced government manipulation is impossible, as losing
bidders will object if a winning bid lower than theirs is announced. For
these reasons Alberta has adopted a policy of announcing only the winning bid
on each tract, and it is recommended that North Carolina do likewise.103

10ODouglas K. Reece, Leasing Offshore Oil: An Analysis of Alternative
information and Bidding Systems (New York: Garland Publishing, 1979), 127 pp.
lOlMead, "Natural Resource Disposal Policy," p. 211.

1021bid., p. 212. A spectacular example of money "left on the table"
occurred on tract 17 in OCS Sale 56 off North Carolina, where the winning bid
of $103.8 million by a group led by Mobil exceeded the next highest bid by
more than $76 million.

103This will require a statutory exception to N.C. Gen. Stat. Chapter
132. The following language to cover this situation and the identities of
applicants (p. 46) could be added as an amendment to N.C. Gen. Stat. �146-8:

Selection of the Lessee

once the bids have been opened, the public agency must decide who, if
anyone, will be offered a lease. There are several considerations:

(1) Who is the high bidder? The success of competitive bidding depends
on the fact that, assuming bidders are qualified, the winner is determined
only by the size of the bid. For all seven offshore programs, the appropriate
statutes or regulations require that if any bid is accepted, it must be that
of the "highest responsible qualified bidder" (Alaska, U.S.) or "the bid most
advantageous to the state" (Louisiana, Mississippi). Where bidding has been
conducted on only one variable, the high bid is immediately evident.

Tie bids are very unlikely, but several programs make provision for them
nonetheless. If the highest bids for an OCS tract are tie bids, MRS requires
that the bidders agree to accept the lease jointly, or else all-bids are
rejected. In Alaska, tied bidders are invited to submit new bids at least
as high as their original bids within 30 days; if the tie is not broken, the
Commissioner may repeat the procedure or award the lease by lot at a public
drawing. Should the highest bids be tied in Texas, all bids are rejected and
the tract is made available for lease again within severalweeks, with a
minimum bid set equal to the previous high bid*104

Assuming the high bids are adequate, the state has an interest in seeing
that a tie-bid tract is leased, and at the highest price and in a fair manner.
The following procedure is therefore proposed for North Carolina. If the
highest bids on a tract are tied, the tied bidders should be invited to submit
new bids at least as high as those already offered. If these are also tied,
the procedure should be repeated or, at the Secretary's discretion, the
bidders should be asked to accept the lease jointly; if they refuse, the lease
should be awarded by lot.

(2) Is the bidder qualified and has the bid been properly submitted? if
eligibility was required to be established before the sale, these questions
can be answered with a quick reference to the appropriate file. otherwise,
eligibility may take several days to establish.

(3) Is the bid sufficient? The question of bid adequacy is a very
complex and occasionally controversial one. There are several approaches that
make use of geologic information, comparable values from nearby leases, sale
results, and other information. The subject will not be discussed further
here, and the interested reader is referred to the recent report on bid
adequacy issued by MMS.105 if all bids are rejected as insufficient, Alaska

If a system of competitive bidding is used to allocate mineral rights,
information related to the identity of applicants and the identities and bids
of unsuccessful bidders shall not be considered public records within the
meaning of Chapter 132 of the General Statutes.

10430 CFR 256.47 (U.S.); 11 AAC 82-455 (Alaska); Tex. Nat. Res. Code Ann.
title 2, �52-019 (Texas).

105 U.S. Department of the Interior, Minerals Management Service,

112

and Louisiana law both permit the tract to be immediately offered again for
lease on a competitive basis, with the requirement in Louisiana that no bids
may be lower than the rejected high bid. @This provision has merit, if used
sparingly, in allowing the government to pursue an adequate bid for a tract it
is interested in leasing without repeating the entire review process,
and is recommended for North Carolina.

(4) Are there anticompetitive implications in issuing a lease to the high
bidder? After every OCS lease sale, the U.S. Attorney General, in consulta-
tion with the Federal Trade Commission, is given 30 days to review sale
results to determine "the likely effects the issuance of such leases would
have on competition," and to make recommendations to the Interior Secretary
.. as may be appropriate to prevent any situation inconsistent with the anti-
trust laws.-106 While antitrust problems are less likely in North Carolina
than on the OCS, they could conceivable arise, and the N.C. Justice Department
should be consulted at least informally before a sale as to what circumstances
would merit further review.

Bidding Mechanics

Detailed bidding instructions should be published with the notice of
sale. Most programs also issue bid forms or sample bids for illustration. At
a minimum bids should include: the lease sale number, the tract bid on, the
amount of the bid (to a suitable number of decimal places if a royalty or
profit-share bid), the amount of the enclosed deposit, the name, authorizing
signature, date, and qualifications file number of the bidder, and if a joint
bid, each of the last four items for each partner, along with the proportion-
ate interest of each.* It is also useful to require instructions for filling
out and sending the lease (if the bid is successful) or for returning the
deposit (if it is not), and the name of the agent authorized to receive
notices on behalf of the bidder(s).

All programs require that a deposit be submitted with the bid as evidence
of the bidder's good faith. These generally vary from 20% to 100% of.the cash
bonus, depending on the program.107 Deposits of unsuccessful bidders are

.Procedures for OCS Bid Adequacy, Including the Final Report of the OCS Fair
Market Value Task Force (Washington, D.Co: Minerals Management Service,
1983), various pagings.
10643 U.S.C. 51337(c); see D.A. Kaplan, "Justice Department Review of
Federal Coal and Oil Leasing: Serving the Consistent Goals of Competition and
Energy Independence," Nat. Reso Lawyer 13:685-693, 1981o
107The deposit required by different programs in recent sales is:
Alabama - 50% of the cash bonus
Alaska - 20% of the cash bonus
California - $50,000 (Point Conception Sale)
Louisiana - 100% of the cash payment (of which the cash bonus
and first year's rental comprise equal portions)
Mississippi- 100% of the cash bonus
Texas - 100% of the cash bonus and 1 1/2% as sale fee
U.S. - 20% of the cash bonus

113

returned after the sale; those of successful bidders are applied to the bonus
payment if leases are executed within the time specified, and are forfeited if
they are not. In some cases the deposit will be substantial, and because of
interest expense it is important that deposits of unsuccessful bidders be
returned as quickly as possible. In most programs, the second highest bidder
can only be offered a lease if the highest bidder is found ineligible. In
programs like Alaska, then, where bidders must pre-qualify, the eligibility of
the high bidder can be determined immediately, and deposits are generally
returned the afternoon of the sale. Programs with eligibility criteria but no
pre-qualification requirement will generally take several days. Similarly,
evaluation of high bids should also proceed quickly so that deposits of
rejected bidders may be returned. Time needed for this step may range from a
week in Alaska to as much as 90 days for the OCS'program. After a certain
period of time (7-10 days?) interest should be included in any refund.

Execution of the Lease

The successful bidder, once notified of his bid's approval, is usually
given a specified period of time after receipt of the lease to execute the
lease, pay the balance of the cash bonus and the first year's rental, and file
any required bonds. Alaska, Califo 'rnia, and the U.S. each require a surety
bond conditioned upon faithful compliance with all provisions of the lease,
while the other four leasing programs do not.108 Such a bond protects the
state in the event that a lessee suddenly goes bankrupt or refuses to meet his
obligations, and it is recommended that North Carolina require a lease bond as
well. Two other bonds may also be required of the lessee during the permit-
ting stage, either by the leasing agency or other state authorities: a
drilling bond for each well drilled, and a bond or insurance to cover
potential oil spill clean-up costs and damages.

Recommendations

The Leasing Process: Application and Review

1. Pre-application contacts. These should be the responsibility of the
Division of Land Resources, and should include advice on the leasing process,
permits required for exploration and development, and the geologic information
already available from previous exploration. P. 47.

2. Application. Areas to be considered for lease should be determined
primarily by unsolicited applications from industry. Aplications should
include (a) the area to be offered for lease, (b) qualifying information
required of all bidders, and (c) a deposit on each block nominated, to be

10830 CFR 256-58-.61 (U.S.); 11 AAC 82.465, 82.600, and 83.160 (Alaska);
Calif. Public Resources Code �6829(d) (California). The amounts required are,
for the OCS: $50,000 per lease or $300,000 per OCS area; for Alaska: a
minimum of $10,000 per lease (may be increased by the Commissioner) or
$500,000 statewide; for California Point Conception leases: $100,000 per
lease plus up to 50% of the replacement cost of fixed structures.

114

returned if the block is not offered or if the applicant bids on it, regard-
less of whether he wins. The identity of the applicant should be kept
confidential. Pp. 45-47.

3. Preliminary review. Upon receipt, the application should be referred to
the Division of Land Resources for conduct of the preliminary review, with
assistance from others as appropriate. The preliminary review should consist
of determinations as to (a) completeness of the application; (b) other,
unnominated areas the state may wish to consider for leasing at the same time;
(c) property rights in the area proposed for lease; (d) condition of the
market for offshore leases; and (e) compatibility of the proposal with
explicit departmental policies on leasing. A recommendation to proceed with
review, with an accompanying timetable, or a recommendation to defer because
of poor market conditions should be forwarded to the Secretary for his
concurrence. Pp. 46-48.

4. Substantive review. If the Secretary approves the proposal for substan-
tive review, he should refer it either to an appointed task force or the
existing OCS Task Force to conduct the review and advise him as appropriate.
Anticipated changes in SEPA regulations make specific recommendations for
review procedures difficult. For illustration, recommended procedures assum-
ing an NRCD task force and existing SEPA rules are shown in Figure 5-3
(p. 54) and consist largely of existing departmental procedures for SEPA
implementation. The major steps of these recommended procedures are:
(1) review of application to determine if leasing is or may be in the public
interest; (2) preparation of a Draft EIS (assuming an EIS is required);
(3) approval by the Secretary and circulation within NRCD; (4) revision as
appropriate and submission of the revised Draft EIS to the state clearinghouse
for distribution to state agencies, regional councils, and local governments,
with concurrent submission by NRCD to appropriate federal agencies, private
groups and others; (5) 60-day review, including public hearing(s) announced in
appropriate newspapers and informal meetings of the task force with interested
groups (oil and gas industry, fishing and tourist industries, environmental
groups, etc.); and (6) review by task force of comments received and decision
whether to recommend to Secretary abandonment of proposal or preparation of
Final EIS, with concurrent consistency review by Coastal Management.
Pp. 52-57.

5. Secretarial decision and notice of sale. If the Secretary decides to
proceed with the lease proposal, having considered all relevant factors
p. 58) a Final EIS and proposed notice of sale should be issued, including a
brief rationale for the Secretary's decision. The notice should include a
description of the areas to be offered, a summary of lease terms, lease stipu-
lations, limitations that will or may be imposed during the permitting stage,
and information on how to qualify for bidding, how to bid, and how the sale
will be conducted. The proposed notice should be released for public comment
through the state clearinghouse and NRCD's own mailing list, and upon receipt
of comments revised as approriate. The notice should then be sent to the
Department of Administration and the Governor and Council of State for
approval, as required by statute, and a final notice issued by the Secretary
and advertised extensively. Pp. 58-59.

115

6. Formal appeals of leasing decisions should be granted at the discretion
of the Department. Pp. 60-61.

7. A proposed timetable for the review process is shown in Table 5-5
(p. 62) a reasonable time frame for the review process, from receipt of an
application to the final notice of sale, is estimated to be 14-16 months. The
state should consider setting the sale date long enough after the final notice
(6-12 months) to permit companies to conduct exploration and prepare bids
after the notice has been issued. Pp. 61-63.

The Leasing Process: Sale

8. Competition should be encouraged by advertising the sale and, where
compatible with other objectives, lowering entry barriers to firms; the latter
.can be promoted by minimizing eligibility criteria and other rules barring
certain bids (particularly joint bids), and by using bidding systems and tract
alignments that lower capital requirements and risk. Pp. 94-98.

9. Uncertainty should be reduced to the greatest possible extent (a) by
making a concerted effort to foresee and announce before the sale the major
environmental restricitons on development that will be imposed on lessees,
and (b) by state consideration of ways to promote cost-sharing and perhaps
some government funding of exploration. Pp. 98-99.

10. The state should consider what qualifications are desirable for bidders.
No specific recommendations are made. Pp. 100-101.

11. The state should use a sealed bidding procedure rather than an oral
auction, and should consider experimentation with sequential bidding.
Pp. 102-104.

12. The state should tailor the bidding system to the particular character-
istics of the sale. Only a single bidding variable should be used on any
single tract, profit-share payments should not be used in the first few sales,
and the state should give serious consideration to the use of bonus bidding
with a sliding scale royalty. Pp. 104-110.

13. A market-based refusal price should not be announced before the sale,
though minimum bids may be. Pp. 110-111.

14. Only the winning bid and bidder should be.publicly announced. P. 111.

15. To determine who,-if anyone, should be offered a lease, sale results
should be analyzed with respect to four questions: who was the high bidder,
is this bidder qualified and was the bid properly submitted, is the bid
sufficient, and are there anticompetitive consequences in issuance of a lease
to this bidder? Pp. 112-113.

16. Bids should include the information listed on p. 113. Deposits should
be required with each bid and should be returned to unsuccessful bidders as
quickly as possible. Pp. 113-114.

116

17. Once the state has decided whom to offer a lease, the successful bidder
should be given a.short period of time to execute the lease, pay the balance
of the cash bonus and first year's rental (if any), and file a bond condi-
tioned on full compliance with the lease. P. 114.

Leasing Considerations: Environmental Protection

18. The state has five different avenues available for environmental protec-
tion during oil and gas leasing and should make use of each as appropriate.
These are:' (1) the decision of which areas to offer for lease; (2) eligibil-
ity criteria for bidders; (3) lease terms and stipulations; (4) regulations on
operations conducted pursuant to the lease; and (5) other laws, regulations,
and permits. Pp. 64-69.

19. In deciding which areas to offer for lease, the difference between
leasing an area and permitting drilling within it should be kept in mind.
Pp. 64-65.

20. Following review of each rejected application, the state should consider
whether the facts of the case warrant promulgation of a temporary moratorium
on leasing within certain areas. A moratorium should be established only
after a public hearing to examinewhere, how long, and why the moratorium
should be in effect. P. 65.

21. The General Assembly should be requested to authorize NRCD to promulgate
rules governing oil and gas operations on state lands. Pp. 66-69.

22. A thorough environmental analysis and review should be conducted before
the saleV not only to determine the advisability of the sale but also to iden-
tify gaps in existing environmental statutes and regulations and to identify
major, likely requirements and restrictions to be imposed on lessees during
the permitting stage. Pp. 71-72.

23. The adequacy of regulatory statutes and rules to govern oil and gas
leasing of privately owned submerged lands should be reviewed in conjunction
with review of the first application, or sooner if needed. P. 72.

Leasing Considerations: Area and Rate

24. The state should continue to use an extension of the OCS grid into state
waters to delineate block boundaries. The presumption should be that these
blocks of 2304 hectares each will be offered individually for lease, but
industry should be given the chance to demonstrate that tracts larger than a
single block are needed to provide sufficient incentive for exploration and
development. Bids on fractions of offered tracts should not be accepted.
Pp. 73-77.

117

25. When a tract is considered for leasing, (a) all claims to property
interests in the tract should be investigated and, where conflicts exist,
resolved if possible; (b) questions of surface access rights and liability
for damages should be researched and fully discussed for the benefit of all
parties; and (c) appropriate lease provisions should be included in oil and
gas leases (and surface leases and easements as well) to-establish and/or
clarify the obligations of the parties involved. The state should also make
it clear to bidders that it does not guarantee title to the oil and gas rights
leased. Pp. 77-83.

26. The state should not make rigid use of checkerboard leasing and surrender
requirements, but should apply the principles of these approaches flexibly as
the situation merits. Pp. 83-85.

27. Special consideration should be given to leasing tracts adjacent to
non-state property that is under or being offered for lease. Pp. 85-86.

28. In deciding how much land to offer for lease and how quickly, the state
should consider the effect of leasing rate on government revenues, economies
of scale, the ability of the state bureaucracy to review applications and
administer leases, and the assimilative capacities of the natural and
socio-economic environments. Pp. 86-88.

Pre-Sale Exploration

29. The state should require all companies conducting oil and gas exploration
in state waters to obtain a permit from the Division of Land Resources.
Pp. 89-90.

30. The General Assembly should be requested to enact a statute authorizing
NRCD to require confidential disclosure of any and all exploration data and
the results of its processing, analysis, and interpretation to the state upon
request. Stringent procedures and penalties should be implemented to minimize
the possibility of unauthorized disclosure. Pp. 90-93.

118

CHAPTER SIX

Lease Administration

This report has already emphasized several times the importance of
working out, before the sale, most of the details of how the lease will be
administered and the lessee regulated. With regards to the post-sale phase of
a leasing program, there are two principal, related'questions to be addressed.
They are: how should the responsibilities of the various state and federal
agencies with regards to oil and gas lease development be coordinated, and
what post-sale authority or control should the leasing agency reserve to
itself through lease terms and regulations?

With respect to the first question, the state has major responsibilities
in four principal areas:

1) Administration of lease provisions. These duties include monitoring
lessee activities, collecting payments, and implementing lease provisions and
stipulations that provide the state with discretionary authority. These
functions can probably be handled most efficiently by Land Resources, with
advice from other divisions and departments as appropriate.

2) Administration of the Oil and Gas Conservation Act, particularly
drilling regulations (currently administered by Land Resources).

3) Administration of the state's water and air pollution control
statutes (currently administered by the Division of Environmental
Management).

4) Administration of CAMA and the State Dredge and Fill Act (currently
administered by the Office of Coastal Management).

A host of other state and federal statutes also apply (see Chapter 3 and
Appendix E), but it is in exercising these four responsibilities, in conjunc-
tion with the permitting authority of the Corps, that the state will largely
determine how the lessee will develop his lease.

it is essential that restrictions imposed under these authorities be
coordinated, to ensure both that the lessee is not unreasonably burdened with
redundant or incompatible requirements, and that the state has used its
authority to cover as many possible impacts and contingencies as are
warranted. There are several means for achieving this coordination, ranging
from informal meetings of representatives from state and federal regulatory
agencies to use of a "permit of last resort" or to a formal procedure compar-
able to the Colorado Joint Review Process. A principal function of the office
of Natural Resources Planning and Assessment is permit coordination, and they
should be called upon to help devise a coordinating procedure for the permit-
ting stage.

With respect to the second question, there are a number of issues in
lease administration that will need to be addressed. These include:

119

1) Should lessees be required to disclose exploration results to the
.state and/or to the public? This issue is similar in many ways to be question
of pre-sale exploration data disclosure discussed in Section 5.5. The Outer
Continental Shelf Lands Act Amendments enacted in 1978 require confidential
disclosure of all data and information obtained from lease exploration,
development, and production on the OCS.1 Supporters of this provision claim
that the Department of the Interior needs this information on tract resources
to protect its interests in the leasing program. However, since a single
exploratory well often provides information on more than just the tract it is
drilled upon, companies have objected strenuously on the grounds that the
right to obtain and protect such data is a valuable asset that is bought along
--with lease development rights by the lessee. They maintain that it is
virtually impossible for government to ensure confidentiality of the data, and
that disclosure therefore creates a risk of data loss without compensation,
thereby creating A disincentive for certain types of expensive drilling
programs.2

North Carolina regulations are currently more stringent than the federal
ones in some respects and more lenient in others. Copies of data from
exploration wells must be submitted to the Department, and confidentiality is
guaranteed for only one year and may be extended for only one more. (Federal
regulations allow confidentiality for two years for some types of data and ten
for others, or until the lease expires, whichever occurs first.)3, In North
Carolina, geophysical results, on the other hand, are not subject to
disclosure.

2) Should lessees be required to submit exploration and/or production
plans for approval? Several leasing programs require, in addition to various
permit applications, that a plan of operations or similar report on proposed
activities be submitted by the lessee for government review and approval.
Regulations may also require that such reports be accompanied by an environ-
mental analysis of the proposed activities. In Alaska, for instance, a Plan
of operations is required of every lessee. In California, lessees must submit
an Environmental Impact Report (under the California Environmental Quality Act
of 1970) that addresses all phases of lease development. OCS lessees must
submit two'plans during the course of lease development, an Exploration Plan
and a Development and Production Plan, each accompanied by an Environmental
Report, while Mississippi offshore lessees must submit three reports, prior to
exploration, appraisal/development, and production.4

143 U.S.C. �1352.

2Russell 0. Jones, Walter J. Mead, and Philip E. Sorenson, "The Outer
Continental Shelf Lands Act Amendments of 1978," Nat. Res. J. 19:885-908,
1979.

315 NCAC 5D .0010; 30 CFR �250.3. The North Carolina regulation does not
appear to be supported by a specific statutory exception to Chapter 132 of the
General Statutes and may be invalid.
4Clause 9 of Alaska standard competitive oil and gas lease and 11 AAC
83.158; Calif. Public Resources Code �21000 et seq.; 30 CFR �250.34; Rule
250) of the Mississippi Rules and Regulations Governing Leasing for

120

The advantages of a plan of operation s are that it provides an overview
of all operations on the lease and also provides an extra degree of control
that can be used to complement the regulatory authority of existing permit
programs. It's major drawback is that it introduces an extra layer of
paperwork and additional uncertainty, both of which will also reduce bids.

3) What steps are necessary to ensure that royalites are received timely
and in the correct amount? Unfortunately the state cannot rely on lessees for
,accurate production and sales data, accurate computation of royalties, and the
timely receipt of royalties owed. Differences in interpretation, mistakes,
and the occasional willful withholding of royalties occur. As a result, the
state will be compelled to devise a system for ensuring that royalties due are
paid promptly or that appropriate penalties are imposed.5 Policies will also
be needed for deciding whether the state should exercise its option of taking
royalties in kind and for the disposition of these royalties.

4) What measures should govern lease assignment, extension, suspension,
and termination? Most programs require that approval be obtained for assign-
ment of any part of a lease, so that the state may ensure that a lease
interest is not subsequently transferred to a party ineligible to bid on it.
Procedures are needed for lease extension, suspension, and termination that
are fair and that give the lessee sufficient opportunity for hearing and
appeal.

Production or Extraction of Oil, Gas, and Other Minerals from State-Owned
Lands, promulgated by the Mississippi Commission on Natural Resources.

5Accurate and timely royalty collection has been one of the most diffi-
cult problems in the federal oil and gas leasing program and has been addres-
sed by a number of studies. See U.S. Commission on Fiscal Accountability of
the Nation's Energy Resources, Fiscal Accountability of the Nation's Energy
Resources (Washington, D.C.: The Commission, 1982), various pagings; U.S.
Government Accounting Office, Oil and Gas Royalty Collections -- Longstanding
Problems Costing Millions, Report AFMD-82-6 (Washington, D.C.: GAO, October
29, 1981), 8 + 33 pp.; U.S. Government Accounting Office, Oil and Gas Royalty
Collections -- Serious Financial Management Problems Need Congressional
Attention, Report FGMSD-79-24 (Washington, D.C.: GAO, April 13, 1979), v +
60 pp.

121

APPENDIX A

Non-Agency Advisory Committee

W.L. Berry Government Relations, Eastern Exploration and
Production Operations, Shell Oil Company,
New Orleans, La.

B-J. Copeland UNC Sea Grant College Program, Raleigh, N.C.

Dirk Frankenberg Curriculum in Marine Sciences, UNC-Chapel Hill,
Chapel Hill, N.C.

S. Henri Johnson N.C. Fisheries Association, New Bern, N.C.

Charles Liner Institute of Government, UNC-Chapel Hill, Chapel
Hill, N.C.

Todd Miller N.C. Coastal Federation, Newport, N.C.

Bruce Muga Department of Civil Engineering, Duke University,
Durham, N.C.

Brad Rice Pamlico County Board of Commissioners, Arapahoe,
N.C.

Angela Waldorf N.C. Petroleum Council, Raleigh, N.C.

State Agency Advisors

Steve Conrad Division of Land Resources, NRCD

T. Stuart Critcher Wildlife Resources Commission

Bill Flournoy Natural Resources Planning and Assessment, NRCD

Joe Henderson, State Property Office, Department of
J.K. Sherron Administration

Derr Leonhardt Industrial Development, Department of Commerce

Dan McLawhorn, Andy Giles,
Allen Jernigan,
Frank Crawley Department of Justice

David Owens office of Coastal Management, NRCD

A-1

William Ross office of Legal Affairs, NRCD

Terry Sholar Division of Marine Fisheries, NRCD

Eric Vernon office of Marine Affairs, Department of
Administration

R. Paul Wilms,
Perry Nelson Division of Environmental Management, NRCD

A-2

APPENDIX B

Acronyms Used in the Text

AEC Area of Environmental Concern

CAMA N.C. Coastal Area Management Act

CFR Code of Federal Regulations

Cos N.C. Council of State

COST Continental Offshore Stratigraphic Test

DOA N.C. Department of Administration

EIS Environmental Impact Statement

EMC Environmental Management Commission

MFC Marine Fisheries Commission

MMS Minerals Management Service

NAAQS National Ambient Air Quality Standards

NCAC North Carolina Administrative Code

N.C.G.S.,
N.C. Gen. Stat. North Carolina General Statutes

NEPA National Environmental Policy Act

NPDES National Pollutant Discharge Elimination Sytem

NRCD, DNRCD N.@C. Department of Natural Resources and Community.
Development

0CM N.C. Office of Coastal Management

OCS Outer Continental Shelf

OSHA Occupational Safety and Health Act of 1970

OSHANC Occupational Safety and Health Act of North Carolina

SEPA State Environmental Policy Act (North Carolina)

U.S.C. United States Code

B-1

APPENDIX C

Petroleum Prospects in the Coastal Plain of North Carolina

1. Formation of Petroleum

Although the processes by which oil and gas form and accumulate are
generally known, there is still much that is poorly understood. Most oil and
gas appears to have its origin in the coastal and shallow marine environments
of estuaries, lagoons, and continental shelves and slopes.1 In these biologi-
cally productive areas, there is a slow, steady rain of organic matter to the
bottom. Where the sediments are sandy and well-aerated, microbial activity
usually decomposes this organic matter completely before it.can become deeply
buried. In finer silts and clays, however, new.deposition may cut off oxygen
diffusion from overlying waters before degradation of the hydrocarbons is
complete. As the sediments become buried under progressively thicker overlying
sediments, temperature and pressure increase, and the entrapped organic matter
undergoes a series of chemical transformations. First, the smaller hydro-
carbon molecules recombine to form a variety of insoluble, complex molecules
collectively known as kerogen. With increasing temperatu e, the kerogen
begins to degrade, releasing first liquid petroleum compounds and then pro-
gressively lighter hydrocarbons until, in the final stages under conditions of
very high temperature and pressure, only methane and a carbon residue remain.
Because temperature and depth are directly related, in any one area the hydro-
carbons generated from a source bed will be a general function of depth
(Figure C-1). Time is also a factor, for like most chemical reactions, the
generation of hydrocarbons proceeds faster at higher temperatures. Petroleum
formation may occur within 5-10 million years of source bed deposition, or may
take as long as 100 million years or more.

Petroleum is never extracted directly from the rock in which it is gener-
ated, for the source beds, formed from silts and clays, are not sufficiently
permeable to allow the petroleum present to flow to a well with the speed
necessary to make extraction economical. Instead, the petroleum engineer
relies on the processes of migration and accumulation to produce petroleum
reservoirs of commercial proportions. The processes causing explusion of
hydrocarbons from source beds are poorly understood, but a major mechanism
appears to be the pressure built up during generation of the petroleum itself.
Expelled from the source beds into more permeable sandstones and carbonates,
the hydrocarbons tend to migrate upwards, driven by their buoyancy relative to
the water filling the pore spaces of the surrounding rocks. This migration
continues until stopped by a barrier or trap. If the trap is sufficiently
large and of the right configuration, and if the rock beneath the trap (known

1Much of the following discussion is drawn from B.P. Tissot.and D.H.
Welte, Petroleum Formation and Occurrence (Berlin: Springer-Verlag, 1978),
and the reader is referred to that work for an excellent and detailed account
of this subject.

C-1

Figure C-1

General Scheme of Hydrocarbon Formation as a Function
of Burial of the Source Rock

Hydrocarbons generated
I7-B7.';.M'ICaI CH4

Geochernical foss Is

2
()ij

After B.P. Tissot and D.H. Welte, Petroleum Formation and Occurrence
(Berlin: Springer-Verlag, 1978).

as the reservoir rock) is sufficiently porous and permeable to hold a large
volume of petroleum, a substantial amount of petroleum may accumulate,
creating a reservoir.

A trap occurs where rock of low permeability to hydrocarbons comes to lie
above rock of higher permeability. Traps are commonly of two types. Struc-
tural traps (Figure C-2) are formed by the folding or faulting of rock layers,
while stratigraphic traps (Figure C-3) are caused by either a nonporous forma-
tion sealing off the top edge of a reservoir bed or by a change in porosity
and permeability within the reservoir bed itself .2 Most of the petroleum
reservoirs found to date have occurred underneath structural traps, but this
may partly be due to the fact that structural traps are easier than strati-
graphic traps to identify with existing exploration technology.

2Petroleum Extension Service, Fundamentals of Petroleum, 2nd ed. (Austin,
Texas: Petroleum Extension Service) University of Texas at Austin, 1981),
p. 15.

C-2

(04C ON..'ry

DOUE

I,CUg-

C.P ROCK

3A&:r PLUG

Figure C-2. Common Types of Structural Traps. From Petroleum Extension
Service, Fundamentals of Petroleum, 2d ed. (Austin, TX: PES,
Univ. of Texas at Austin, 1981), p. 12.

IE
IC

@Figure C-3. Common Types of Stratigraphic Traps. From Petroleum
Extension Service, Fundamentals of Petroleum, 2d ed. (Austin,
TX.: PES, Univ. of Texas at Austin, 1981), p. 15.

c-3

'Miller and others3 list several criteria that petroleum-producing areas
must possess: (1) an adequate thickness of sedimentary rocks; (2) source beds
containing considerable dispersed organic matter; (3) a suitable environment
for the maturation of organic matter; (4) porous and permeable reservoir beds;
(5) hydrodynamic conditions favorable for both early migration and ultimate
entrapment of oil and gas; (6) a favorable thermal history; (7) adequate
trapping mechanisms; and (8) suitable timing of petroleum generation and
migration in relation to the development of traps. The key question is,
to what extent are these conditions present, or have have been present, in
eastern North Carolina?

2. Geology of the North Carolina Coastal Plain

The North Carolina coastal plain is part of a much larger system of
Mesozoic and Cenozoic sediments that stretch from Florida to Newfoundland.
Within the state the sediments form a wedge-shaped mass, thickening eastward
from a feather edge along the fall line to 10,000 feet at Cape Hatteras and to
more than 35,000 feet in the Carolina Trough on the Outer Continental Shelf.4
The basement beneath these sediments is comprised primarily of igneous and
metamorphic rocks of Precambrian and Paleozoic age, similar to those that crop
out in the Piedmont. The basement surface appears to slope gently toward the
sea at slopes ranging from 10 feet/mile inland to as much as 120 feet/mile
near the ocean. For the most part this slope is perpendicular to the Appa-
lachians. In southeastern North Carolina, however, there occurs a distinctive
structure known as the Cape Fear Arch, a broad, southeast plunging nose in the
basement surface. The arch and the general slope to the east together account
for the varying thicknesses of sediments overlying the basement surface, from
1100 feet near Cape Fear, to 5000 feet at Cape Lookout and 10,000 feet at Cape
Hatteras.5

These overlying sediments crop out in broad belts that roughly parallel
the coastline. The oldest occur farthest west and are buried progressively

3B.M. Miller, H.L. Thompsen, G.L. Dolton, and others, Geological
Estimates of Undiscovered Recoverable Oil and Gas Resources in the U.S.,
Geological Survey Circular 725 (Reston, Va.: U.S. Geological Survey, 1975),
p. 17.
4Stephen G. Conrad, P. Albert Carpenter, III, and William F. Wilson,
"Physiography, Geology, and Mineral Resources," Ch. 5 in James W. Clay,
Douglas M. Orr, Jr., and Alfred W. Stuart, eds., North Carolina Atlas (Chapel
Hill: University of North Carolina Press, 1975), p. 117; Jeffrey L. Deis,
Frederick N. Kurz, and Elizabeth 0. Porter, South Atlantic Summary Report 2,
U.S. Geological Survey Open-File Report 82-15 (Reston, Va.: Minerals Manage-
ment Service, 1982), p 31.

5 John C. Maher, Geologic_Framework and Petroleum Potential of the
Atlantic Coastal Plain and Continental Shelf, Geological Survey Professional
Paper 659 (Washington, D.C.: U.S. Geological Survey, 1971), p. 22.

C-4

deeper as one moves east (Figure C-4). The sedimentary sequence is reviewed in
detail in several publications6 and will not be discussed at len.gth here. For
the most part, the sedimentary rocks exposed onshore are continental and near-
shore marine clastics, with occasional interspersed beds of marl and lignite *7
As one moves east, the sedimentary sequence becomes thicker, younger, and in-
creasingly marine in origin. Of all North Carolina wells drilled to date, the
thickest and most completely marine section was found at Cape Hatteras, where
all but the basal 700 feet of the 9900 feet of sedimentary rock drilled
through is essentially marine in origin. The bulk of the section was de-
posited between the Lower Cretaceous and the Miocene (approximately 100 to 10
million years ago), and consists of roughtly 40 percent sandstone, 30 percent
carbonate rock (limestone, dolomite, and others), and 30 percent shale.8

3. Petroleum Potential of Eastern North Carolina

To date, there have been no finds of oil or gas of commercial size in the
U.S. Atlantic coastal plain. The potential for oil or gas in eastern North
Carolina has been a subject of disagreement among professional geologists for
years. Large areas of the coastal plain remain unexplored, and the possi-
bility exists that commercial reservoirs of petroleum may yet be discovered.

Coastal North Carolina does possess some of the prerequisites for petro-
leum accumulations. Source beds for hydrocarbons, generally regarded to be
marine shales, marls, and limestones in roughly that order of importance, are
scattered throughout the sedimentary sequence beneath the coastal plain; at
Cape Hatteras they make up more than half of the sequence.9 Moreover asphalt
has been found at varying depths in several wells in the outer plain.10 Inland
the sedimentary rocks, more continental in origin, are more likely to be
sources of dry gas than of oil. Reservoir rocks (primarily sandstones and
limestones) are thick and numerous beneath the Atlantic Coastal Plain, and
several thick sandstone and limestone beds with good reservoir characteristics
were found at the Cape Hatteras well.

6See Maher, Geologic Framework, and Philip M. Brown, James A. Miller, and
.Frederick M. Swain, Structural and Str atigraphic Framework-, and Spatial,
Distribution of Permeability of the Atlantic Coastal Plain, North Carolina to
New York, Geological Survey Professional Paper 796 (Washington, D.C.: U.S.
Geological Survey, 1972).
7Maher, Geologic Framework, pp. 26-27.
8J. Spivak and O.B. Shelburne, "Future Hydrocarbon Potential of Atlantic
Coastal Province," pp. 1295-1310 in Ira H. Cram, ed., Future Petroleum
Provinces of the United States -- Their Geolou and Potential, Memoir 15, 2
vols. (Tulsa: American Association of Petroleum Geologists, 1971), Vol. 2,
p. 1306.
9Maher, Geologic Framework, p. 58.
1OPhilip M. Brown et al., Structural and Stratigraphic Framework, Cross
Section Z" - Z".

C-5

Figure C-4

Structural Cross-Section Across the Coastal Plain
to the Continental Rise at Cape Hatteras, North Carolina

B#E BN
COASTAL PLAIN---tT ALOPIE4-CONTINENTAL RISIE-
CAPE HATTERAS
f
MCI NC2 MC3 VC4 NCS Me& NCT Mee Net SEA LEVEL
0"'CE
0
0 EOCENE
C'C rACCOUS
Se E47. C e"'
140 MILES B." IO.OW
1,94,v, PO
@83 901

0 -'Ve
z rig
-2000' 11

6.SDOOQF

INDEX MAP 4000',
............
T 0. 4044'
GRANITE

PRE C goo

CARSOINATE

SANDSTONE

smALz
-$DOW

MILE3 DIEV. CIABASE

T 0. 10.054'
GRANITIC

From John C. Maher, Geologic Framework and Petroleum Potential of the
Atlantic Coastal Plain and Continental Shelf, Prof. Paper 659 (Washington,
D.C.: U.S. Geological Survey, 1971).

A variety of potential traps exist in coastal plain sediments. Sealing
beds, usually of clay, shale, or salt, are a necessary ingredient of most
petroleum traps, and beds of clay and shale are relatively common in the North
Carolina sedimentary sequence.11 Though the coastal province has been very
quiet tectonically during the deposition of these sediments, studies continue

IlMaher, Geologic Framework, pp. 61-62.

C-6

to find many small faults and anticlinal structures that could serve as petro-
leum traps. Stratigraphic traps, such as pinch-outs, channel fills, offshore
bars, and buried reefs, are also thought to occur in scattered locations.

It is the question of thermal maturity that casts doubt on the petroleum
generating potential of eastern North Carolina sediments. As explained
earlier, source rocks require a prolonged period at sufficient temperature
(50* - 100*0 for the kerogen matrix to generate liquid and gaseous hydro-
carbons. The lower the temperature, the longer the period needed. Although
the geothermal gradient varies from place to place, it is thought that 10,000
feet is an approximate minimum depth in the coastal plain for the necessary
combination of temperature andItime to produce petroleum. Work elsewhere
along the Atlantic coast tends to support this view. Six exploratory wells
drilled in the Southeast Georgia Embayment on leases sold in OCS Sale 43 were
all dry. The deepest strata penetrated by the COST well drilled in the
Embayment, at a depth of approximately 10,800 feet, seem to be thermally
mature but are continental deposits and therefore inferior as a source of
petroleum.12 Several younger, shallower strata exhibit good to very ood
source-generating potential, but appear to be geothermally immature.19
Modelling studies by Angevine and Turcotte suggest that optimum conditions
for petroleum generation along the Atlantic continental margin are found at
depths of 20,000 - 26,000 feet.14

The most likely location of source beds that have been subjected to the
right combination of time and temperature is the far eastern edge of the
coastal plain, where sediment thickness of 9,000-10,000 feet and more occur.
Elsewhere in the coastal plain it seems unlikely that potential source beds
have reached thermal maturity. This is not to say, however, that the poten-
tial for finding petroleum.in eastern North Carolina is equally low. In some
instances oil and gas are known to have migrated many-miles from their source
beds to the reservoirs from which they were ultimately produced. Especially
considering the general dip of coastal strata to the east, it is quite
possible that petroleum formed at.greater depths in the Outer Continental
Shelf has migrated up to the west and been trapped in coastal plain sediments.
Only continued exploratory drilling can confirm or deny this possibility.

While most petroleum exploration in North Carolina has historically
focused on the coastal plain, other locations in and near the state are
receiving interest. Further offshore beyond the three-mile limit, the sedi-
mentary sequence is considerably thicker, and the possibility of thermally
mature source beds is much greater. This,'combined with the presence of
faults, salt domes, buried reefs, and other potential traps, has made the

12Deis, Kurz, and Porter, South Atlantic Summary Report 2, p. 31.
13 Ibid.; Stephen W. Brown, Paul J. Cernock, and Joseph A. Haykus,
"Regional Hydrocarbon Source-Rock Evaluation of Atlantic Coastal Plain
Adjacent to Georgia Embayment" (abstract), Am. Assoc. Pet. Geol. Bull.
63(3):425-426, 1979.
14Charles Angevine and D.I. Turcotte, "Thermal Evolution of Sedimentary
Basins Along Atlantic Continental Margins of United States" (abstract),
Am. Assoc. Pet. Geol. Bull. 64(5):670, 1980.

C-7

North Carolina OCS one of the most promising new offshore areas for petroleum
development. Exploratory drilling in this region, expected to begin soon, may
throw more light on the potential for petroleum in North Carolina waters as
well.

Other areas that have attracted interest are the eastern overthrust belt
in western North Carolina and the Triassic sediments found in downfaulted
basins in the Piedmont.

C-8

APPENDIX D

Environmental Impacts of Petroleum Exploration and Development
in North Carolina Submerged Lands

The impacts of oil and gas development in coastal North Carolina will
vary because of the diversity of coastal environments and the different tech-
nologies used in these environments. The following sections describe each of
the major activities that take place during petroleum exploration and develop-
ment, the range of options for accomplishing each, and the potential impact of
each approach. These accounts are designed to be introductory rather than
exhaustive and should provide the reader with an idea of guidelines and regu-
lations that might be imposed to control environmental impacts at socially
acceptable levels.

For more information the reader is referred to the reference footnotes of
this chapter and to a number of excellent studies that have been published
over the last decade. These include general reports on coastal and offshore
petroleum developmentl and reports that focus on specific phases of such
development (particularly pipelines).2 Two major studies in the Gulf have

William L. Longley, Rodney Jackson, and Bruce Snyder, Managing Oil and
Gas Activities in Coastal Environments: Refuge Manual, Publication FWS/OBS-
-91/2-2 (Washington, D.C.: Office of Biological Services, U.S. Fish and Wild-
life Service, 1981), 451 pp.; William L. Longley, Rodney Jackson and Bruce
Snyder, Managing Oil and Gas Activities in Coastal Environnments, Publication
FWS/OBS-78/54 (Washington, D.C.: Office of Biological Services, U.S. Fish and
Wildlife Service, 1978), 66 pp.; David J. Brower, William D. McElyea, David R.
Godschalk, and Nancy D. Lofaro, Outer Continental Shelf Development and the
North Carolina Coast: A Guide for Local Planners, CEIP Report No. 5 (Raleigh,
N.C.: N.C. Department of Natural Resources and Community Development, 1981),
256 pp.; John Clark and Charles Terrell, Environmental Planning for Offshore
Oil and Gas, Volume III: Effects on Living Resources and Habitats, Publica-
tion FWS/OBS-77/14 (Washington, D.C.: Office of Biological Services, U.S.
Fish and Wildlife Service, 1978), 220 pp.; W.H. Conner, J.H. Stone, L.M. Bahr
and others, Oil and Gas Use Characterization, Impacts and Guidelines, Sea
Grant Publication LSU-T-76-006 (Baton Rouge, La.: Sea Grant Program,
Louisiana State University, 1976), 148 pp.; New England River Basins Commis-
sion, Factbook (Boston, Mass.: New England River Basins Commission, 1976),
various pagings.
2F. Yates Sorrell, Richard R. Johnson, Charles D. Wyman and others, Oil
and Gas Pipelines in Coastal North Carolina: Impacts and Routing Considera-
tions, CEIP Report No. 33 (Raleigh, N.C.: N.C. Department of Natural
Resources and Community Development, 1982), 266 pp.; Ann W. Gowen amd Michael
J. Goetz, Pipeline Landfalls: A Handbook of Impact Management Techniques
(Cincinnati, Ohio: U.S. Environmental Protection Agency, 1981), 201 pp.; Ann
W. Gowen, M.J. Goetz, and I.M. Waitsman, Choosing Offshore Pipeline Routes:

D-1

atte ted to assess the cumulative ecological effects of offshore develop-
mentl
The Environmental Impact Statements and other environmental documents
issued by the Minerals Management Service for OCS activities contain a wealth
of data relevant to North Carolina waters, particularly those seaward of the
barrier islands. Fewer impact statements for shallow water activities have
been issued; one useful series is the set of three EIS's prepared by the Corps
of Engineers for Mobil's exploration and development of the Lower Mobile Bay
Gas Field in Alabama.4

1. Geophysical Exploration

Commercially exploitable petroleum deposits are formed when organic
matter is heated to produce oil or gas and these products are collected and
concentrated by geological structures called "traps." Looking for such trap-
ping structures is the purpose of geophysical exploration.

Modern geophysical exploration uses sound waves to probe beneath the
earth's surface. As these sound waves travel through sediment and rock, a

Problems and Solutions, Report No. EPA-600/7-80-114 (Cincinnati, Ohio: U.S.
Environmental Protection Agency, 1980), 92 pp.; Robert J. Golden, Jr., Kenneth
Gallagher, Norbert P. Psuty and others, OCS Natural Gas Pipelines: An
Analysis of Routing Issues (New Brunswick, N.J.: Center for Coastal and
Environmental Studies, Rutgers--The State University of New Jersey, 1980),
432 pp.; A.H. Rooney-Char and R.P. Ayers, Offshore Pipeline Corridors and
Landfalls in Coastal Virginia, Special,Report in Applied Marine Science and
Ocean Engineering No. 190, 2 vols. (Gloucester Point, Va.: Virginia Institute
of Marine Science, 1978); Charles A. Willingham, Barney W. Cornaby, and David
G. Engstrom, A Study of Selected Coastal Zone Ecosystems in the Gulf of Mexico
in Relation to Gas Pipelining Activities (Columbus, Ohio: Battelle Columbus
Laboratories, 1975), various pagings; John T. McGinnis, Robert A. Ewing,
Charles A. Willingham and others, Environmental Aspects of Gas Pipeline
22erations in the Louisiana Coastal Marshes (Columbus, Ohio: Battelle
Columbus Laboratories, 1972), various pagings.
3Brian S. Middleditch, ed., Environmental Effects of Offshore Oil Pro-
duction: The Buccaneer Gas and Oil Field Study, Marine Science Vol. 14 (New
York: Plenum Press, 1981), 446 pp.; C.H. Ward, M.E. Bender, and D.J. Reish,
eds., "The Offshore Ecology Investigation: Effects of Oil Drilling and Pro-
duction in a Coastal Environment," Rice University Studies 65 (4-5): 1-589,
1979.

4U.S. Army Corps of Engineers (Mobile District), Final Environmental
Statement, Permit Application by Mobil Oil Corporation, Exploratory Oil Well,
Mobile Bay, Alabama (Mobile, Ala.: U.S. Army Corps of Engineers, 1976),
various pagings; U.S. Army Corps of Engineers (Mobile District), Final
Environmental Impact Statement for Four Exploratory/Appraisal Hydrocarbon
Wells, Mobile Bay, Alabama (Mobile, Ala.; U.S. Army Corps of Engineers, 1980),
various pagings; U.S. Army Corps of Engineers (Mobile District), Production of
Natural Gas from the Lower Mobile Bay Field, Alabama, Final Environmental
Impact Statement (Mobile, Ala.: U.S. Army Corps of Engineers, 1982), various
pagings.

D-2

small percentage of their energy is reflected back toward the surface after
encountering changes in rock and/or sediment type. Recording the highly
amplified echos from these reflections provides remotely sensed data on the
shape, depth, and geometry of the reflecting surfaces.5 Surfaces that have
been deformed to create downward facing basins are known to sometimes trap oil
and gas formed around or under them. While drilling is the best way to
determine subsurface geology and the presence of oil or gas, it is also
expensive, hence the interest in finding the traps in advance of drilling.

Geophysical exploration of rocks under the seafloor is done by vessels
that tow long cables carrying numerous underwater microphones and a large
sound source. Early technology used explosions for the sound source, but now
release of compressed air (air gun) or an el'ectrical discharge (sparker) is
used.6 The noise from this source travels over many paths to the microphones.
The paths of interest for geophysical exploration pass into the seafloor, off
rock surfaces beneath it, and back up through the seafloor to the microphones.
These echoes are recorded and analyzed for evidence of the shape of subbottom
rock surfaces. Modern geophysical survey ships record 96 or.more different
sound frequencies at one time, and the expense of analyzing the data can make
a-mile of modern multichannel subbottom profiling cost as much to produce as a
mile of superhighway. The environmental impact of such activity is negli-
gible. The passage of the vessel and the possibility that a few marine
animals may be stunned or killed by the air bubble or spark are the only
general problems. Possibilities for accident, loss of cable, etc., exist but
are small for a competently run operation.

Unfortunately seismic subbottom profiling from ships is not always
possible or practical in nearshore areas such as those in North Carolina. Not
only does shallow water limit areas where deep draft (ca. 12 feet) geophysical
survey vessels can operate, but enclosed and crowded waters also make it
impossible to deploy long (ca. 1/2 mile) towed instrument arrays. In addi-
tion, sound sources that are effective in deep water produce bottom echoes
in shallow.water that can confound data retrieval. Thus other geophysical
exploration techniques are needed in shallow water and salt marsh habitats.
The technique most often used on the Gulf of Mexico coastline is a modifica-
tion of terrestrial procedures that use explosives. In this operation a
shallow hole is drilled into the marsh, an explosive charge is placed within,
recording microphones are positioned along "shot" lines running away from the
explosion site, and, when everything is in place, the charge is detonated to
produce sound waves that pass downward to reflect off subsurface features.7

The environmental impact of this procedure can be substantial. The
explosion obviously creates noise, air pollution and a hole, but pre-explosion
construction may also have lasting impact on coastal wetlands. In current
practice the drill rig is positioned'on "rig mats" made of removable boards,
but associated access roads, levees, cable laying, and human presence may have

5j. Kennett, Marine Geology (Englewood Cliffs, N.J.: Prentice Hall,
Inc. 1982), xv + 813 pp.

6Ibid.

7Longley et al., Managing Oil and Gas Activities: Refuge Manual.

D-3

substantial impacts on salt marsh habitats. In coastal marshes much of the
human access and cable laying is by marsh buggies. These vehicles operate on
either large, low-pressure rubber tires or tank-like treads. Although these
devices spread the vehicle's weight over a large surface area, marsh buggies
still produce ruts on most marsh surfaces. These ruts enhance water movement
over the marsh, often producing luxuriant growth of marsh grass for many years
after vehicle passage. Marsh plants are extremely susceptible to changes in
marsh height or drainage characteristics, so all construction activities that
alter these features of the environment can be expected to have a significant
impact. Increasing the level of the sediment surface or decreasing drainage
may render the environment intolerable to marsh plants or any other vegeta-
tion.8 On the other hand, decreasing sediment height or increasing drainage
usually increases growth and vigor of salt marsh grasses (Spartina spp.),
and may actually increase the productivity of the marsh ecosystem. Which, if
either, of these impacts results from construction for explosion-based geo-
physical exploration will depend on the specific construction procedures used
at specific sites and cannot be described in detail in advance.

2. Dredging and Filling

Coastal oil and gas development may require dredging and/or filling in
conjunction with three separate operations: provision of access to the well
site, preparation of the well site itself, and pipeline installation. The
standard drilling structure in coastal waters less than 20 feet deep (most of
North Carolina's inshore waters) is the submersible drilling barge. A typical
barge measures 50 by 180 feet and for transport generally requires a channel
70 or more feet wide and 8-10 feet deep. Where water depths are shallower,
dredging of an access canal will be necessary. At the well site itself, a
larger area known as the slip must be excavated in shallow waters to accommo-
date not only the drilling barge but also the supply barges and barges that
hold the drilling muds. When the barge arrives on site, the ballast tanks are
flooded and the barge sinks until its hull rests on the bottom, providing a
stable platform for drilling operations. In water depths over 10 feet, a
shell pad may be laid first to provide a sufficiently shallow bottom for the
barge to rest upon.

Access to marsh drill sites may be achieved either by dredging an access
canal through the marsh, or by building a road out from dry land for transport
of a land rig. The choice will depend on the location of the site relative to
existing channels and roads, the ability of the marsh soil to support heavy
equipment, the decisions of regulatory agencies, and other factors. Where a
road is to be built, standard practice has been to use marsh soils adjacent to
the roadway for the road base, and then to construct a board road on top,
capped with earth, sand, or shell where the road is to be used over a long
period. In some cases, the boards may be placed directly on the original
marsh surface, or the road may be built entirely with fill from outside the
marsh area. At the well site, draglines construct a levee (approximately 400
feet square) around the site from marsh soils. The rig is placed on a board

8D.S. Ranwell, Ecology of Salt Marshes and Sand Dunes (London: Chapman
and Hall, 1971), xiv + 258 pp.

D-4

rig mat laid directly on the marsh surface. Steel mud pits are now favored
over pits excavated in-the marsh itself.

For reasons of safety and stability, most utility lines (including oil
and gas lines) crossing marshes and coastal waters are buried beneath the mud
surface. The practice of the Minerals Management Service in the Gulf offshore
waters has been to require burial of pipelines more than 8 inches (22 cm) in
diameter; smaller lines may or may not be buried, depending on the preferences
of the operator and conditions specific to the area. In open water, burial is
accomplished by excavating a trench either before the line is laid, next to
the laid line, or from beneath the laid line; the line is then placed in the
trench, except in the latter case where it settles into the trench naturally.
The trench is backfilled or left to backfill naturally. In marsh areas, a
trench is excavated first, the pipeline is constructed at one end and floated
into the trench as the line is constructed, and the floats then cut away and
the trench backfilled over the settled pipeline.

A great deal of research on the impacts of dredging and filling in
estuarine systems has been conducted in recent years. Nevertheless, our
understanding of this subject is far from complete, and predictions of
specific impacts are not yet possible with much assurance. The effects of
dredging have been the subject of several recent reviews9 and of an extensive
research effort (the Dredged Material Research Program) of the Corps of
Engineers. The impacts of oil rig access canals and pipeline canals have been
specifically addressed by a number of authors.10

The major ecological impacts of dredging and filling in estuarine systems
can be grouped into four categories:

alteration or destruction of habitat where the canal is dredged and
where the spoil or fill is placed;

9Sam A. Johnston, Jr., "Estuarine Dredge and Fill Activities: A Review
of Impacts," Environmental Management 5(5):427-440, 1981; Kenneth 0. Allen and
Joe W. Hardy, Impacts of Navigational Dredging on Fish and Wildlife:
A Literature Review, Publication FWS/OBS-80/07 (Washington, D.C.: Office of
Biological Services, U.S. Fish and Wildlife Service, 1980); James W. Morton,
Ecological Effects of Dredging and Dredge Spoil Dis2osal:_ A Literature
Review, Technical Paper No. 94 (Washington, D.C.: U.S. Fish and Wildlife
Service, 1977), 33pp.
1OSee, e.g., Longley et al., Managing Oil and Gas Activities: Refuge
Manual; Conner et al., Oil and Gas Use Characterization; McGinnis et al.,
Environmental Aspects of Gas Pipeline Operations; N.J. Craig, R.E. Turner, and
J.W. Day, Jr., "Land Loss in Coastal Louisiana," pp. 227-254 in: J.W. Day,
Jr., D.D. Culley, Jr., R.E. Turner, and A.J. Mumphrey, Jr., eds., Proceedings
of the Third Coastal Marsh and Estuary Management Symposium (Baton Rouge, La.:
Louisiana State University Division of Continuing Education, 1979); Gerald
Adkins and Philip Bowman, A Study of the Fauna in Dredged Canals of Coastal
Louisiana, Technical Bulletin No. 18 (New Orleans, La.: Louisiana Wildlife
and Fisheries Commission, 1976), 70pp.

D-5

- increases in suspended sediment and its various effects on the water
column;

- sedimentation; and

- changes in estuarine and marshland hydrology.

Th ese effects will have secondary consequences for commercial and recrea-
tional fishermen and other users of estuarine waters. In addition, dredging
and filling activities may disturb archaeological and historic artifacts.

The most immediate impact of dredging and filling in estuaries is the
destruction of benthic organisms where sediments are dredged and spoil or fill
placed. Recolonization tends to be highly variable in time and species com7-
position, and its nature appears to depend on substrate characteristics, the
biology of the plants and animals involved, and a variety of other factors.
Generally the more naturally variable the environment, the better adapted the
biota is to unstable conditions and disturbances like dredging and filling.11
In estuaries, recolonization is often rapid and original biomass may be
reached within a few weeks, though colonizers tend to be opportunistic species
and species diversity remains depressed for some time.12

Laboratory and field studies have found considerable variation in the
abilities of benthic animals to escape from under a blanket of sediment.
Sessile animals, such as barnacles, oysters, and mussels, are destroyed, as
are most epifaunal forms. Many of the infauna. have demonstrated abilities to
migrate upward through dredged material in the lab, but few field studies have
found any contribution to recolonization of spoil deposits from vertical
migration.13 Sedimentation from settling materials or from spoil redistrib-
uted by currents may smother oysters or render substrate unsuitable for spat
attachment.14 On the other hand, shell platforms placed at drilling siter, may
provide good additional substrate for the development of oyster populations.

The effects of canal or road construction through marshland will gener-
ally be to replace highly productive marsh with less productive open water
(canal) or upland (spoil banks), or with nonproductive road. The amount of

11Nina D. Hirsch, Louis H. DiSalvo, and Richard Peddicord, Effects of
Dredging and Disposal on Aquatic Organisms, DMRP Technical Report DS-78-5
(Vicksburg, Miss.: U.S. Army Engineer Waterways Experiment Station, 1978),
po 17*
12Allen and Hardy, Impacts of Navigational Dredging, p. 17.
13Hirsch et al., Effects of Dredging, pp. 15-17.
14 Curt D. Rose, "Mortality of Market-Sized Oysters (Crassostrea
virginica) in the Vicinity of a Dredging Operation," Chesapeake Science
14:135-138, 1973; Ronald.Fiore, "Oyster Reefs," pp. 73-87 in: Raymond Alden,
David Brower, B.J..Copeland and others, Ecological Determinants of Coastal
Area Management, Vol. II: Appendices, Sea Grant Publication UNC-SG-76-05
(Raleigh, N.C.: UNC Sea Grant College Program, 1976).

D-6

marsh whose productivity is directly reduced or eliminated by canal construc-
tion is generally several times the canal width, due to spoil placement,
traffic and other construction activities. Marsh destruction does not end
with canal construction, however. Experience in the Gulf shows that, over
time,, access and pipeline canals may enlarge dramatically through bank
erosion. Recent work also suggests that man-made canals may be responsible
for the major portion of coastal Louisiana's alarming rate of land loss of 102
km2/year probably through interruption of local and regional hydrologic
regimes.15 A number of design measures have been suggested to mitigate these
impacts.16

Research has catalogued a range of potential environmental effects that
may be caused by sediments suspended during dredging and filling operations.
These include: a decrease in light penetration, resulting in reduced photo-
synthetic activity; various physical and pathological effects on fish and
intertebrates, particularly gill function; the release of nutrients and toxic
substances (both natural and man-made) from disturbed sediments; interference
with animal migrations; and reduction in dissolved oxygen levels. However,
many of these same studies show that turbidity levels generated by
dredging are comparable to those created by trawling and natural storm events,
and that for the most part the impacts listed above are observed only in
localized instances.17

Canals and adjacent spoil banks (when deposited linearly) may disrupt
estuarine circulation, thereby altering patterns of salinity, temperature,
dissolved oxygen, sediment movement, and water exchange. A classic example of
these effects is that of South Bay, near Brownsville, Texas. Dredged material
from the Brownsville ship channel was placed along the north end of South Bay,
closing it off except for a narrow, shallow inlet. As a result, Boca Chica
Pass, South Bay's other inlet, filled in, circulation in South Bay became
virtually non-existent, the average depth decreased from 1.2 to 0.4 m, the
oyster pofulation was destroyed, and fish and other invertebrate populations
declined. 8

Marshland hydrology will also be altered by canal or pipeline ditch
construction, with potentially deleterious impacts on marsh productivity.
Results may include greater saltwater intrusion into the marsh; diversion of
freshwater upland runoff from the marsh surface, thereby draining the marsh
and depriving it of nutrient and sediment input; and impoundment of water on

15William W. Scaife, R. Eugene Turner, and Robert Costanza, "Coastal
Louisiana Recent Land Loss and Canal Impacts," Environmental Management,
in press.
16Scaife et al., "Recent Land Loss"; Craig et al., "Land Loss in Coastal
Louisiana"; Longley et al., Managing Oil and Gas Activities: Refuge Manual.
17Sorrell et al., Oil and Gas Pipelines in Coastal North Carolina,
pp. 89-91.
18Joseph P. Breuer, "An Ecological Survey of the Lower Laguna Madre of
Texas, 19,53-1959," Publ. Inst. Mar. Sci. (U. Texas) 8:143-183, 1962.

D-7

the marsh surface by spoil levees.19 Such changes may lead to significant
shifts in marshland vegetation and animal distribution patterns. In recent
years there has been a trend in the Gulf states towards requiring the back-
filling of pipeline canals, thereby substantially reducing these impacts.

3. The Presence of Structures and Boats

The presence of drilling rigs, platforms, and construction and supply
vessels may affect navigation and shipping, fishing activities, visual
quality, and other uses of the state's territorial waters.

The major impact on marine shipping and navigation will be the presence
of exploration rigs and drilling and production platforms. Navigational or
operational errors in the vicinity of platforms may result in collisions. The
danger is highest early in field development, before vessel traffic adjusts to
the presence of these structures. In the Gulf, where currently over 80,000
ships each year cross waters containing 3700 structures, 12 major collisions
with OCS structures occurred in the period 1963-1977, including one involving
fatalities.20 The Coast Guard has established a uniform system of aids
to navigation for identifying offshore structures and minimizing such
collisions.21

Other hazards include the increased traffic generated by supply boats,
crew boats and other oil-related vessels which often move across customary
lanes of travel. Geophysical survey vessels towing instrument arrays and
pipeline construction and bury barges have limited mobility and may disrupt
other marine activities and vessels. Fishing boats also have limited mobility
when towing gear and are sometimes placed on automatic pilot to free up an
additional crewman for handling gear; during these times, increased vessel
traffic will create an additional hazard to them. Stipulations attached to
OCS Sale 42 on Georges Bank and the proposed California lease sale off Santa
Barbara County require oil and gas operators to train vessel captains and
platfor and shore-based supervisors in commercial fishing methods; whether
such training is effective in reducing conflicts is an open question. A
related hazard, particularly to commercial fishermen, is the trash and debris
sometimes lost or dumped overboard by oil and gas operators. The state may
wish to consider implementing a program comparable to the federal Fisherman's
Contingency Fund or the Louisiana Gear Loss Fund to compensate fishermen for
gear damage attributable to oil and gas operations.

Loss of access by commercial fishermen to the area occupied by drilling
rigs and platforms is another concern. The amount of spatial exclusion will
depend on many factors: type of fishing gear, vessel maneuverability, rig or
platform configuration and mooring, weather and sea conditions, legal and

19Sorrell et al., Oil and Gas_Pipelines in North Carolina, pp. 142-147.
20 U.S. Department of Interior, Minerals Management Service, Final
Regional Environmental Impact Statement, Gulf of Mexico, 2 Vols. (Metairie,
La.: Minerals Management Service, 1983), Vol. 1, p. 402.

2133 CFR �67.

D-8

safety requirements, and the fisherman's experience and willingness to take
risks. The loss of access in areas occupied by subsea structures will be
determined by the accuracy with which fishermen can fix the location of the
obstruction. Such obstructions will be few in state waters: subsea comple-
tions are installed only in the deep waters of the OCS, and pipelines will be
buried at most locations within North Carolina's boundaries. These and other
potential conflicts between the fishing and oil industries have recently been
reviewed by Centaur Associates.22

Structures on submerged lands (particularly platforms, but also unburied
pipelines) may also act as artificial reefs, providing hard substrate for the
development of a biofouling community. Fish are attracted to such structures
by the presence of food, shelter, calm water or favorable currents, and the
orientation apparently provided by a solid object.23 Structures in the Gulf
are notorious for their good recreational fishing, and some researchers
attribute the rise of a major recreational fishery in this region in the last
30 years largely to construction of offshore drilling pl Iatforms.24

oil and gas activities and structures may present some conflict with
military use of state waters. A number of danger zones have been established
in the state's territorial waters; these include target areas, bombing and
rocket firing areas, ordnance test areas, and firing ranges. The regulations
governing civilian use of these areas may be found at 33 CFR �204. Two areas
of restricted navigation, near Cherry Point Marine Corps Air Station and Sunny
Point Military Ocean Terminal, have also been established (33 CFR �207). The
extent to which oil and gas operations could be conducted within these areas
would have to be negotiated with the Department of Defense on a case-by-case
basis.

Finally, exploration rigs and drilling and production platforms will in
most cases have a negative visual impact. The degree of impact will depend on
the quality of the surrounding environment, the distance of the rig or plat-
form from the viewing area, and the number of people to whom the structure is
visible.

4. Oil Spills

Oil spills will probably be the environmental impact most feared by North
Carolinians during coastal petroleum exploration and development. There is
good scientific reason to fear oil spills in coastal waters. Spills can have
significant short- and long-term detrimental impacts. Water bird and marine
mammal populations can be destroyed, beaches can be rendered inconvenient or

22Centaur Associates, Inc., Assessment of_S2ace and Use Conflicts Between
the Fishing and Oil Industries, 3 vols. (New York: Bureau of Land Management,
U.S. Department of Interior, 1981).
23R.B. Stone, "Artificial Reefs and Fishery Management," Fisheries 3:2-4,
1978.

24 Ronald Dugas, Vincent Guillory and Myron Fischer, "Oil Rigs and off-
shore Sport Fishing in Louisiana," Fisheries 4:2-10, 1979.

D-9

unusable for swimming by tar balls or crude oil, intertidal marshes can be
killed back and intertidal animal populations affected for years following an
oil spill incident. Not all coastal oil spills cause these adverse effects,
but widely publicizied spills have caused them, thus they will be feared.
Some coastal spills have had minimal adverse impacts, but this is largely due
to these spills having been carried offshore by wind and currents. Seaward of
the barrier islands, wind and current patterns are such that some coastal
spills will be dispersed offshore while others will be carried towards beaches
and tidal inlets. In inside waters (bays, sounds and estuaries) the full
impact of the spill will be borne by marine environments well known for their
sensitivity to oil pollution.

At the same time, it is important to maintain a perspective on the like-
lihood of an oil spill. The offshore oil industry has compiled a commendable
safety record in recent years. The spill rates currently used by the Minerals
Management Service to estimate lease sale impacts are 1.0, 1.6, and 1.3 spills
of 1,000 barrels or greater per billion barrels produced or transported for
platforms, pipelines, and tankers, respectively.25 Between 1971 and 1982, 55
spills over 50 barrels, totalling 67,979 barrels in all, occurred in the
federal waters of the Gulf. During the same period, approximately 3.79
billion barrels of oil and condensate were produced, resulting in a spill rate
of .0018%. Spills from well blowouts have become very rare. The last blowout
to result in an oil spill in federal waters occurred in 1970; since then,
over 12,000 wells have been drilled and 79 blowouts have occurred, none with
spillage of more than a barrel.26

The environmental effects of oil spills include the physical impact of
oil in coastal habitats and biological effects ranging across a spectrum from
acute toxicity to long-term, sublethal disturbance. The severity of all
impacts is influenced greatly by the type and age of oil spilled.

The term petroleum refers to a complex mixture of chemicals composed
mostly of hydrogen and carbon (hydrocarbons). The chemistry of petroleum
changes radically after it is spilled. These changes are caused by evapora-
tion of light components and chemical and biological oxidation of heavier
components. The changes lead to formation of pelagic tar that floats or sinks
depending on its.density. The differences between petroleum from
different sources and at different ages from the same source make specific
predictions of environmental impact impossible.

The general environmental impacts of oil spills in coastal habitats are
well known. Pelagic tar is an environmentally long-lived end product of oil
spill degradation, and tar on beaches is a predictable outcome of oil spills

25Kenneth J. Lanfear and David E. Arnstutz, "A Reexamination of Occur-
rence Rates for Accidental Oil Spills on the U.S. Outer Continental Shelf,"
presented at the 1983 Oil Spill Conference, San Antonio, Texas; copies avail-
able from MMS. The figures for platforms and pipelines were based on OCS
data, while the one for tankers is based on the worldwide spill record.
26U.S. Department of the Interior, Minerals Management Service, Federal
Offshore Statistics (Washington, D.C.: Minerals Management Service, 1983),
pp. 49, 53, 86-87.

D-10

in coastal waters. General biological effects are almost equally predictable.
Animals that live at (water birds) or breathe through (marine mammals, sea
turtles, etc.) the air-water interface are severely affected by oil spills.27
Sea birds are particularly susceptible to oil because it sticks to their
naturally oiled feathers and is ingested as the birds preen. While efforts to
clean birds after oil spills have largely been unsuccessful in the past,
considerable progress has been made in recent years in developing successful
and cost-effective procedures. The Torrey Canyon oil spill killed 40,000 to
100,000 birds, mostly auks, on both sides,of the English Channel.28 Marine
mammals also suffer greatly from contact with spilled petroleum. Those with
hair (seals, otters, muskrats, etc.) have problems similar to those described
for sea birds. Hairless marine mammals (whales, porpoises and the like) seem
to have fewer problems. These animals have often been observed near major oil
spills without showing obvious distress or mortality.29 The impact of oil on
sea turtles is not well known, although it has been suggested that the impact
may be great because sea turtles not only breathe air, but also may be
attracted to oil spills.

The impact of oil on aquatic, gill-breathing animals ranges from acute
toxicity to sublethal effects of various sorts. Physical smothering of
coastal organisms by oil is one of the most often observed features of an oil
spill.30 It is often difficult to determine the exact cause of death, but
physical or chemical interference with feeding and respiratory activities are
obviously involved. The catalog of sublethal effects of oil on marine animals
is long and constantly expanding. The 1975 report of the U.S..National
Academy of Sciences3l includes a nine-page table summarizing 46 papers that
document sublethal effects on reproduction, growth, metabolism, behavior, and
cellular structure. Many of the species demonstrating these effects are found
in North Carolina inshore waters.

5. Drilling Fluids and Cuttings

Drilling for oil is accomplished by a bit suspended on the end of a pipe,
both of which are rotated by engines on the drilling platform. The rotating
bit cuts through sediment and rock under the platform to reach potentially

27A. Nelson-Smith, Oil Pollution and Marine Ecology (New York: Plenum,
1973), ix + 260pp.
28W.R.P. Bourne, "Special Review -- After the Torrey Canyon Disaster,"
This 112:120-125, 1970.
29D.R. Goodale, M.A. Hyman, and H.E. Winn, "Cetacean Reponses in
Association with the Regal Sword Oil Spill," Chapter XI, pp.1-15 in: A
Characterization of Marine Mammals and Turtles in the Mid and Nol@t_h AtTantic
Areas of the U.S. Outer Continental Shelf, Ann. Report for 1979, USDOI BLM
Contract #AA551-CT8-48, 1981.
30Nelson-Smith, Oil Pollution and Marine Ecology.

31National Academy of Sciences, Petroleum in the Marine Environment
(Washington, D.C.: National Academy of Sciences, 1975), xi + 107pp.

D-11

oil-bearing strata. As the drill moves deeper into the substratum, new
sections of pipe are added to extend its total length. Adding pipe adds
weight and friction at the drill bit. The bit is lubricated and cuttings re-
moved by fluids (drilling fluid or "mud") pumped inside the drill pipe. The
pressure of the fluids is sufficient to flush through the hollow drill bit,
clear it of rock and sediment cuttings, and transport these to the surface
along the outside of the rotating drill string. Fluid pressure is also used
to control seepage from surrounding strata into the drill hole. Since drill
bits wear, and different bits are used in different substrates, the entire
drill string must be periodically withdrawn from the hole. At these times the
pressurized drilling fluid is the only force maintaining the well. The mul-
tiple important uses of fluids in oil drilling have led to development of a
distinct technology for handling, cleaning, and using them. Fluids are
usually maintained in tanks or pits on or near the drilling platforms. As
much as 70 percent of the drilling site may be devoted to drilling fluid
equipment and storage.32 Waste fluids are discharged into the environment as
cuttings are washed, fluid composition is adjusted or volume expands because
of seepage. Fluids are also disposed of as a well is closed down or converted
to production. More than two million tons (dry weight) of waste drilling
fluids are discharged annually on the U.S. Outer Continental Shelf.33 Some
discharges of these materials can be expected if North Carolina waters are
explored and developed for petroleum recovery.

The principal ingredients of drilling fluids are bentonite or attapulgite
clays (to increase viscosity and create a gel), barium sulfate ("barite," a
weighting agent), lime and caustic soda (to increase the pH and control
viscosity), and various conditioning materials (polymers, starches, lignitic
material, and other chemicals).34 Most muds have a water base, but oil-based
muds may be used in special situations, such as where bottom hole temperatures
are very high, where water-based muds would hydrate water-sensitive clays, or
where the drill pipe is stuck.35 The chemicals used in a "typical" lignosul-
fonate drilling fluid system in a 15,000-foot well are presented in Table D-1.

The environmental impacts of drilling fluid disposal include physical
alteration of the sediments where waste fluids are deposited and biological
effects that vary widely depending on the specific type of fluid being dis-
charged. Biological effects of drilling fluids are generally related to the
minor components of drilling fluid, and these vary widely from fluid to
fluid.36 Diesel fuel is sometimes added to enhance lubrication of the drill

32Longley et al., Managing Oil and Gas Activities: Refuge Manual.
33National Research Council, Drilling Discharges in the Marine
Environment (Washington, D.C.: National Academy Press, 1983), p. 2.
34U.S. Environmental Protection Agency, Development Document for Interim
Final Effluent Limitations Guidelines and Proposed New Source Performance
Standards for the Oil and Gas Extraction Point Source Category, Publication
EPA 440/1-76/055-a (Washington, D.C.: U.S.E.P.A., 1976), p.12.

351bid.

36National Research Council, Drilling Discharges in the Marine
Environment.

D-12

Table D-1

Drilling Fluid Components Used in Seawater-Lignosulfonate
Systems to 15,000 Feet

Weight in Thousands of Pounds*

Sub- Sub-
Interval total Interval total Interval TOTAL
0- 900- 3500- 10-
@900 3500 3500 10,000 10,000 15,000 15,000
Feet Feet Feet Feet Feet Feet Feet

Barium Sulfate
(Barite) 3 3 6 529 535 625 1,160
Bentonitic Clay 10 10 20 36 56 9 65
Attapulgite Clay 5 5 10 - 10 - 10
Caustic 0.5 0.5 1 20 21 23 44
Aromatic Detergent 1 1 2 3 - 3
Organic Polymers 1 1 3 4 - 4
Ferrochrome
Lignosulfonate 26 26 69. 95
Sodium Chromate 2 2

TOTALS 18.5 20.5 39 616 655 728 1,383
(691.5
tons)

*These are "typical" values and quantities may vary by as much as 50
percent from well to well. (From U.S. Department of Interior, Bureau of Land
Management, Final Environmental Statement, Proposed Five-Year OCS Oil and Gas
Lease Sale Schedule, March 1980-February 1985 (Washington, D.C.: Bureau of
Land Management, 1980), p. 151.)

bit, and as mentioned above oil-based fluids may be used in a variety of
situations.. Non@-petroleum additions to drilling fluids can include hexavalent
chromium for deflocculation control.,37 biocides to retard microorganism
growth, and detergents and surfactants to decrease surface tension.38

37F. Knox, The Behavior of Ferrochrome Lignosulfonate in Natural Waters,
M.S. Thesis, Mass. Inst. Tech., Cambridge, Mass., 1978. 65pp.
38R.C. Ayers, T.C. Sauer, Jr., R.P. Meek, and G. Bowers, "An Envirorr-
mental Study to Assess the Impact of Drilling Discharges in the Mid-Atlantic
on Environmental Fate and Effects of Drilling Fluids and-Cuttings.

D-13

Drilling fluids discharged from shallow water drilling platforms are
diluted by diffusive discharge, settle through the water column, and are
incorporated into bottom materials. These processes occur over distances from
the platform that differ in response to currents, environmental turbulence,
and discharge diffuser design. Outfall diffusers can be designed to reduce
drilling fluid concentrations by several orders of magnitude within a few
the outfall pipe,39 and observations of drilling fluid plumes show that con--
centrations drop to less than 50 parts per million (solids concentration)
within 150 meters of the discharge point.40 More than 90 percent of dis-
charged drilling mud and cuttings settle directly to the seafloor.41 Studies
of sediment concentration of drilling fluid components around discharge points
show that concentrations decrease inversely with radial distance, and in low
current situations most of the solids settle within 1,000 meters of the dis-
charge.42 Resuspension and subsequent movement of settled drilling fluid
particles can occur, but drilling fluids can be expected to alter bottom
sediment type and chemistry near discharge sites in shallow water.

In general the biological impact of any waste materials placed in an
environment can include acute toxicity, sublethal long-term effects and
bioaccumulation in natural food chains. Drilling fluids have been studied in
relation to all three impacts. The major ingredients of water based drilling
fluids (barite, bentonite clays, etc.) are practically non--toxic, but
ferrochrome-lignosulfonate and sodium hydroxide are moderatley toxic (i.e.,
concentrations between 100-1000 ppm kill 50 percent of test organisms within
96 hours),43 while biocidal constituents can be very toxic to marine organisms
(concentrations of less than I ppm kill 50 percent of test animals within 96
hours). -Sublethal long-term effects of drilling fluids on marine animals have
been studied relatively little, but some impacts of practically non-toxic
substances have been observed. Recruitment of sandy-bottom worms and molluscs

I. Quantity and Fate of Discharges," pp. 382-418 in: S posium on Research
on Environmental Fate and Effects of Drilling Fluids and Cuttings (Washington,
D.C.: Courtesy Associates, 1980).
39j.M. Colonell, ed., Port Valdez, Alaska: Environmental Studies,
1976-1979, Occ. Pub. 5 (Fairbanks, Alaska: Inst. Mar. Sci., 1981), 373pp.
40Ayers et al., "An Environmental Study to Assess the Impact of Drilling
Discharges in the Mid-Atlantic."

41Ibid.

42D.A. Gettleson and C.E. Laird, "Benthic Barium in the Vicinity of Six
Drill Sites in the Gulf of Mexico," pp. 739-788 in: Symposium on Research on
Environmental Fate and Effects of Drilling Fluids and Cuttings (Washington,
D.C.: Courtesy Associates, 1980).
43j.B. Sprague and W.L. Logan, "Separate and Joint Toxicity to Rainbow
Trout of Substances Used in Drilling Fluids for Oil Exploration," Environ.
Pollut. 19:269-281, 1979.

D-14

was significantly inhibited by barite,44 and some species of shrimp accumulate
barium abnormally when exposed to barite for long periods.45 Biological
accumulation of heavy metals from drilling fluids has been observed in experi-
ments with animals of the sort that occur in North Carolina waters. These
experiments show that worms, clams, shrimp, and mussels take up such metals as
chromium, cadmium, lead, and zinc and do not rid themselves of these metals
even after being kept in metal-free sea water for periods of up to 14 days.46

The recent National Academy of Sciences report on Drilling Discharges in
the Marine Environment is the most comprehensive study of this problem yet.47
While the study was directed at the U.S. Outer Continental Shelf, many of its
findings can be extended with care to nearshore waters. The study included a
useful summary table of the biological effects of drilling fluid components
(reproduced here as Table D-2); the data summarized in this table and con-
sidered in greater detail in the NAS report led the NAS panel to conclude:

Based on laboratory and field studies to date, most water-based
drilling fluids used on the U.S. OCS have low acute and chronic toxici-
ties to marine organisms in light of the fluids' expected or observed
rates of dilution and dispersal in the ocean after discharge. Their
effects are restricted primarily to the ocean floor in the immediate
vicinity and for a short distance downcurrent from the discharge. The
bioaccumulation of metals from drilling fluids appears to be restricted
to barium and chromium and is observed to be small in the field.48

6. Formation Waters

Sedimentary strata that contain petroleum also contain water. Initially
it was thought that petroleum and water were not mixed in subsurface deposits,

44M.E. Tagatz, J.M. Ivey, C.E. Dalbo, and J.L. Oglesby, "Responses of
Developing Macrobenthic Communities to Drilling Muds," Estuaries 5:131-137,
1982.

45A.C. Brannon and K.R. Rao, "Barium, Strontium, and Calcium Levels in
the Exoskeleton, Hepatopancreas, and Abdominal Muscle of the Grass Shrimp
Palaemonetes pugio: Relation to Molting and Exposure to Barite," Comp.
Biochem. Physiol. 63A:261-274, 1979.
46D.S. Page, B.T. Page, J.R. Hotham, and others, "Bioavailability of
Toxic Constituents of Used Drilling Muds," pp. 984-996 in: Symposium on
Research on Environmental Fate and Effects of Drilling Fluids and Cuttings
(Washington, D.C.: Courtesy Associates, 1980); W.L. McCulloch, J.M. Neff, and
R.S. Carr, "Bioavailability of Heavy Metals.from Used Offshore Drilling Muds
to the clam Rangia cuneata and the oyster Crassostrea gigas," in: Symposium
on Research on Environmental Fate and Effects of Drilling Fluids and
Cuttings (Washington, D.C.: Courtesy Associates, 1980).
47National Research Council, Drilling Discharges in the Marine
Environment.

48Ibid., p. 112.

D-15

Table D-2

Summary of Biological Effects of Drilling Fluids and
Drilling Fluid Ingredients on Marine Animals

LABORATORY STUDIES
Acute Lethal-STo-assays
Parameter (LC50 Range, ppm) Chronic/Sublethal Effects*

Drilling Fluid Ingredients

Barite, Bentonite, Lignite >10,000 5mm layer on sediment

Chrome- & Ferrochrome-
lignosulfonates 120-12,000 50 ppm

Chromium (VI) 0.5-250 12 ppb

Diesel Fuel 0.1-1,000 10 ppb water, 100 ppm
sediment

Paraformaldehyde 0.07-30 10 ppb

Detergents,,Surfactants 0.4-14,000 -

Used Drilling Fluids of 400 Bioassays: 1-160,000 ppm in water
38% > 100,000 1-12 mm layer on bottom
41% 10,000-99,999 50-100,000 ppm affects
12% 1,000-9,999 recruitment to microcosms;
6% 100-999, some bioaccumulation of
0.5% < 100 barium and chromium
3% LC50 not deter- demonstrated.
minable

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

FIELD STUDIES

Community Responses Effects seen only on benthos in the vicinity of
discharge and are most pronounced in low-energy
environments where discharges accumulate on
bottom.

Bioaccumulation of Metals**_ Small uptake of barium and chromium immediately
after drilling

*Lowest concentration at which effects are observed.
**There are no specific data available on the bioaccumulation of
hydrocarbons.

From: National Research Council, Drilling Discharges in the Marine
Environment (Washington, D.-=..- National Academy Press, 196j), p. 111.

D-16

but now it is known that these compounds occur together, often as an emulsion.
As a result, oil production recovers water as a byproduct. The water recov-
ered from oil wells is known variously as formation water (since it occurs in
the same geological formation as the oil) or produced water (since it is
produced along with the oil). The amount of this water varies in different
oil fields and at different times in the development of the same field. Most
commonly the ratio of water to oil increases as oil is pumped from the field.
Over the life of an oil field, the U.S. Geological Survey estimates that the
ratio of recovered water to recovered oil is 0.8, i.e. for every barrel of oil
recovered, 0.8 barrels of formation water is also recovered. In old oil
fields the recovered fluid may be five percent oil and 95 percent water.49

The composition of formation waters varies widely, but usually includes
lithium, sodium, potassium, rubidium, cesium, calcium, magnesium, strontium,
barium, boron, copper, chloride, bromide, iodide, bicarbonate, carbonate,
sulfate, organic acids, and ammonium.50 Most of these elements occur at
concentrations much higher than that of sea water, and the overall concentra-
tion of salts is commonly three to ten times as high as normal sea water. The
relative proportions of salts in formation waters and sea water differ,
however. Rittenhouse and.others5l studied 823 oil field brines and found that
manganese, lithium, chromium, and strontium were enriched relative to sea salt
and tin, nickel, magnesium and potassium were depleted.

In the early days of oil production formation waters were simply dumped
nearby and allowed to kill surface vegetation and the fish in streams draining
the oilfield, but now these brines are often injected back into the oil for-
mation to increase petroleum recovery and, in some cases, control land sub-
sidence.52 In many nearshore and Outer Continental Shelf oil wells, however,
these brines are disposed of at sea.

Disposal of formation waters in marine waters mus t meet EPA requirements
that these waters contain no more than 72 mg/l of oil. Statistical analyses
of formation water discharged in the Gulf of Mexico show an average oil con-
tent of 25 mg/l petroleum. 3 EPA does not regulate disposal of chemicals
other than oil in formation waters. Some of the chemicals in formation waters
(e.g., copper) are known to be toxic to marine organisms, but the wide vari-
ability in composition and amount of formation water produced makes it impos-
sible to realistically predict the impact of environmental disposal of such

49 A. Gene Collins, "Geochemistry of Oilfield Waters," in: Developments
in Petroleum Science, Vol. I (New York: Elsevier, 1975), 1 + 496 pp.

501bid.

51G. Rittenhouse, R.B. Fulton, R.J. Grabowski, and J.L. Bernard, "Minor
Elements in Oil Field Waters," Chem. Geol. 4:189-209, 1969.
52A. Gene Collins, "Geochemistry of Oilfield Waters."
53U.S. Department of the Interior, Minerals Management Service, Final
Environmental Impact Statement, OCS Sale 78, Proposed 1983 Outer Continental
Shelf Oil and Gas Lease Sale Offshore the South Atlantic States (Washington,
D.C.: Minerals Management Service, 1983), p. 155.

D-17

waters from a virgin oil field. Some states have enacted more stringent
controls. California, for instance, regulates effluent concentrations of more
than a dozen different metals and toxic compounds in produced waters for off-
shore disposal. The oil and gas industry has found it more practical to
reinject formation waters than to treat them for surface disposal.

It is possible that environmental disposal of formation waters would have
an adverse environmental impact on the biologically productive nearshore
waters of North Carolina. Such disposal may need to be regulated, and it may
be appropriate to require reinjection of formation waters rather than offshore
disposal.

7. Other Discharges

In addition to drilling muds and cuttings and formation waters, several
other wes of liquid wastes may be routinely generated at offshore well
sites:5

1) deck drainage (all waste resulting from platform washings, deck
washings, and run.--off from curbs, gutters, and drains, including drip pans and
work areas);

2) sanitary waste;

3) domestic waste (materials discharged from sinks, showers, laundries,
and galleys);

4) cooling water ("noncontact" water used for cooling machinery); and

5) desalinization unit discharges (generated by desalinization of salt
water).

The volume of liquid wastes generated varies widely with platform char-
acteristics, operating schedule, occupancy, and other factors. Data gathered
by EPA for several offshore facilities whose staffing ranged from 10 to 76 men
showed combined domestic and sanitary waste production ranged from 1,000 to
5,500 gallons per day.55 Deck drainage and heating and cooling waters dis-
charged from platforms amount to roughly 90 gallons per day.56 Mobil esti-
mated that total liquid wastes (including domestic and sanitary wastes, deck
drainage, drilling mud liquids, and various wash waters) from their drilling

54U.S. Department of the Interior, Final Regi2nal Statement, Vol. 1,
p. 364; U.S. Environmental Protection Agency, Development Document, p. 38.
55U.S. Environmental Protection Agency, Development Document, p. 52.
56U.S. Department of the Interior, Bureau of Land Management, Final
Supple ent to the Final Environmental Statement, Proposed Five-Year -OCS Oil
and Gas Lease Sale Schedule, January 1982-December 1986, 2 Vols. (Washington,
D.C.: Bureau of Land Management, 1982), Vol. 1, p. 270.

D-18

operations in Mobile Bay would average 9800 gallons per day per drilling
7
barge.5

Treatment practice for these wastes varies. Deck drainage may be treated
separately or along with formation waters to remove oil and grease; this
treatment may be carried out on the platform or onshore. Sanitary wastes are
usually treated on the platform with some combination of physical/chemical or
physical/biological treatment, but in some cases they are tanked to shore for
disposal. Domestic wastes only require grinding to eliminate floating
solids.

Discharge of these wastes is regulated to some extent by EPA through the
National Pollutant Discharge Elimination System (NPDES). Effluent limitations
have been established for oil and grease, residual chlorine (as a substitute
for fecal coliform) and floating solids, though these standards do not apply
in all situations.5A Some states have enacted more stringent and/or compre-
hensive regualtions. Alabama, for instance, has implemented a no-discharge
policy for offshore wells: all wastes, including deck drainage, domestic
wastes, and others, must be transferred to shore for disposal.

8. Air Pollution

In most areas air pollutant emissions from offshore oil and gas opera-
tions create little concernf since such operations do not generate large
volumes of pollutants (relative to many other industrial facilities), and
since sources are often miles from the nearest land, allowing pollutants to be
diluted and dispersed over substantial distances before landfall is made.
However, near urban or industrial concentrations where onshore air quality is
already poor (as in southern California), or near pristine areas where any air
quality degradation is noticeable, emissions from offshore operations may
receive considerable attention.

Offshore emissions may be divided into two categories: those from
routine operations and those generated during accidents. The major source of
routine emissions during exploration will be power generation equipment. Mud
pumps and rig drawworks are the principal consumers of electricity during
drilling; additional power is needed to supply the rotary and various acces-
sories and housekeeping activities. If convenient, the power may be supplied
by cable from shore, but more often it is generated at the drilling site by
diesel-fired turbines or (usually) reciprocating engines.59

57U.S. Army Corps of Engineers (Mobile District), Final Statement for-
Four Exploratory/Appraisal Wells, p. C-8.
58 40 CFR 5435; see also U.S. Environmental Protection Agency,
Development Document.
59Richard H* Stephens, Charles Braxton, and Maynard M. Stephens, Atmos-
pheric Emissions from Offshore Oil and Gas Development and Production,
Publication EPA-450/3-77-026 (Research Triangle Park, N.C.: U.St, Environ-
mental Protection Agency, 1977), pp. 81-83.

D-19

Other sources of emissions during exploration are the dredging and con-
struction equipment used to build an access canal or road to the drill site,
and the supply boats that ferry supplies and crew to the rig. In addition, if
the drill bit passes through a gas reservoir, gas may seep into the well bore
and become dissolved or entrained in the drilling mud. When this happens, mud
degassing equipment must be used at the surface to remove an 10gas fromthe
mud, and the liberated gas is then vented to the atmosphere.
These activities and their associated emissions continue during field
development, but added to them are the emissions generated by vessels and
equipment engaged in platform construction and pipeline installation. The
amount and location of these latter emissions will vary tremendously with
platform and pipeline design, construction methods, and other factors.

The major source of emissions during the production phase will be power
generation for gas compression (for artificial gas lift, re-injection, and/or
transmission to sho're), oil pumping (for other artificial lift methods and
transmission to shore), water injection (for water flood or formation water
disposal), and various miscellaneous uses (lighting, cooking, process motors,
etc.).61 Other emissions during production include those from direct-fired
heaters used in processing the produced fluids, fugitive emissions from com-
pressor, pump, and valve seals, and gas vented from storage tanks. If oil is
barged to shore, large amounts of hydrocarbons can be emitted by the displace-
ment of hydrocarbon vapor during barge loadings, and to a lesser extent by
tanker cargo breathing.62

Representative emissions from these activities are shown in Table D-3.
The combination of platform and pipeline construction and high production
levels normally results in peak emission rates occurring during the year after
production begins. Emissions decrease abruptly with the end of construction
activity and continue to decline as production levels decline.63

Accidents involving loss of well control -- oil spillsi blowouts, and
fires -- have the potential for releasing significant quantities of pollutants
to the atmosphere. One study estimated that hydrocarbons are emitted from an
oil spill at the rate of 57 lbs/barrel during the first hour of the spill and
29 lbs/barrel during the second hour.64 Blowouts release hydrocarbons at
rates comparable to the full production rate of the well, which for a well

601bid., p. 89.
61Ibid., p. 93.
62U.S. Department of Interior, Final Supplement, Vol. 1, p. 169; U.S.
Department of Interior, Bureau of Land Management, Final Environmental State-
ment, Proposed Five-Year OCS Oil and Gas Lease Sale Schedule, March 1980-
February_1985 (Washington, D.C.: Bureau of Land Management, 1980), p. 154.
63U.S. Department of Interior,.Final Statement, 1980-1985, p. 154.
64U.S.- Department of Interior, Final Supplement, Vol. 1, p. 169.

D-20

Table D-3

Operational Emissions from Offshore Oil and Gas Activities

Activity Pollutant Emissions (tons/year)

VOC NOX TSP S02 CO Notes

Exploration Drilling 18 180 13 12 40 Emissions valued from VCAPD
(1981) assumes 60 days/well
and 6 wells drilled near
same site, i.e., constant
drilling in same area over
the full year.

Platform Installation 16 465 22 31 75 Emission values from ERG
(1981) assumes platform
installation occurs over 9
months; includes support
activities.

Development Drilling 9 240 11 21 71 Emission values from ERG
(1981) assumes 2 wells
drilled at a time and 12
wells per year.

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

Activity Power Requirement

Oil Production
Electrical Generation (oil pumping, platform
electricity, miscellaneous) 5,300 hp-hr/103 bbls.
Water Injection 3,000 hp-hr/103 bbls.
Barge loading - 1.7 lb Hc per 103 gal transferred
(crude oil)

Gas Production and Processing
Gas Compression (lift, gathering, sendout) 6,100 hp-hr/106 ft.3
Offshore Gas Processing (compression for heavy /106 ft.3
hydrocarbon removal, sweetening, dehydration) 3,200 hp-hr

(continued on next page)

D-21

Table D-3 (continued)
Note: Emissions factors for power requirements are as follows (pounds/103
hp-hr):

NOx CO HC S02 TSP

2.9 1.1. 0.2 0.004 NA

Source: U.S. Department of Interior, Bureau of Land Management, Final
Supplement to the Final Environmental Statement,, Proposed Five-Year
OCS Oil and Gas Lease Sale Schedule,_January 1982-December 1986, 2
Vols. (Washington, D.C.: Bureau of Land Management, 1982),,Vol. 1,
pp. 382-383.

producing one million cubic fe .et per day is roughly 2000 lbs/hour.65 Gas
reservoirs also frequently contain hydrogen sulfide, and during blowouts
concentrations of H2S near the rig may approach dangerous levels. If the
escaping gas is accidentally or purposely flared, typical combustion emissions
(nitrogen and sulfur oxides, carbon monoxide, particulates) will replace the
hydrogen sulfide and much of the hydrocarbon emissions. Representative emis-
sion rates from these accidents are given in Table D-4.

Finally, offshore exploration and production may be accompanied by
emissions from a variety of onshore sources, including support bases, fabri-
cation yards, pump and compressor stations, oil refineries, and gas processing
plants. Representative emission rates for these facilities have been compiled
by the New England River Basins Commission.66

9. Employment

Employment benefits to the local economy are generally small during
exploration but increase during development and production. In an OCS,
exploratory program, a total of 130 to 200 people will be employed on the rig
and in operating supply boats, helicopters, and onshore support services. A
typical drill barge used in nearshore waters, with attendant supply and
onshore services, will reguire only 75 personnel, including two shifts of 30
each on the barge itself. 7 Most of these employees will be skilled trans-
ients, working 7-14 day shifts on the drilling vessels and usually flying home
during their weeks off. There will be relatively few local hires.,

651bid.; Stephens et al., Atmospheric Emissions, p. 91.
66New England River Basins Commission, Factbook.
67 JohrCClark, Jeffrey Zinn, and Charles Terrell, Environmental Planning
for Offshore Oil and Gas, Volume 1: Recovery Technology, Publication No.

D-22

Table D-4

Representative Emissions of Catastrophic Events

Emissions (lbs/hr)

Accident Type THC NOx sox CO TSP H2S

140 Barrel Spill
First Hour 8,000 -
Second Hour 4,100 -

10,000 Barrel Spill
First Hour 570,000 -
Second Hour 290,000 -
(Evaporation losses during the first 10 days of an
oil spill are assumed to be approximately 45%)

Blowout-No Fire* 2,000 - 33

Blowout-With Fire* 670 46 417 670 140

*Assuming blowout 1,000 mcfd and 1,000 bod.

Source: U.S. Department of Interior, Bureau of Land Management, Final
Supplement to the Final Environmental Statement,_Proposed Five-Year
OCS Oil and Gas Lease Sale Schedule, January 1982-December 1986, 2
Vols. (Washington, D.C.: Bureau of Land Management, 1982), Vol. 1,
pp. 382.

During field development-and production, the number of employees, the
percentage of local hires, and the amount of in-migration are all likely to
increase. For example, Tables D-5 and D-6 show estimated employment during
development and production,, respectively, for the Lower Mobile Bay Gas Field
in Alabama being developed by Mobil. Development plans call for five produc-
tion platforms, up to 20 wells, a pipeline system, and gas processing plant.

The secondary employment multiplier will increase from negligible levels
during exploration to perhaps 0.5 for the development phase and 1.0 for
production.

FWS/OBS-77/12 (Washington, D.C.: Office of Biological Services, U.S. Fish and
Wildlife Service, 1978), p. 72; Interstate Electronics Corporation, "Environ-
mental Report-Exploration, South Atlantic-OCS, Lease Sale 56, Blocks 422, 466,
510, Manteo Area," prepared for Chevron U.S.A., Inc., 1982, p. 2-3; U.S. Army
Corps of Engineers (Mobile District), Final Statement for Four Exploratory/
Appraisal Wells, p. 57.

D-23

Table D-5

Employment During the Construction Phase of
Development of the Lower Mobile Bay Field, Alabama

Estimated Peak Estimated
Estimated Construction Local
Activity Duration of Work Employment Hires

Drilling 6 years 90 5

Drilling Services 6 years 70 35

Offshore Site Preparation 1 month/platform* 20 10

Platform Installation 1 month/platform* 80 5

Offshore Facilities 4 to 6 months* 40 5

Offshore Pipeline
Installation 5 months 120 10

Onshore Pipeline
Installation 3 months 100 60

Gas Plant Construction 12 months 350 225

Road and Other
Construction 3 months 50 35

Sulfur Depot/
Railroad Spur 3 months 80 60

TOTALS 1,000 450

*Work will not be performed at the sam time for each platform.

Source: U.S. Army Corps of Engineers (Mobile District), Production of Natural
Gas from the Lower Mobile Bay Field, Alabama, Final Environmental
Impact Statement (Mobile, Ala.: U.S. Army Corps of Engineers, 1982),
p.4-44.

D-24

Table D-6

Employment During the
Operation Phase of Development of the Lower
Mobile Bay Field, Alabama

Location of Estimated Estimated
Employment Employment Local Hires

Bayou La Batre 6 1

Boats 6 4

Platforms 24 10

Plant 27 10

Sulfur Depot 7 3

TOTAL 70 28

D-25

APPENDIX E

Legislation, Regulation, and Permitting

This appendix is divided into two parts and serves as a supplement to
Chapter 3. The first section gives a brief description of state and federal
legislation that will influence the exploration and development of submerged
lands for oil and gas. This section is divided by subject area into laws
dealing with environmental protection, navigation and construction, business
and employment practices, and historic and cultural preservation. Where one
piece of legislation applies to more than one of these subject areas, it has
been classified under the most significant topic.

The second portion of this appendix lists and describes permitting,
licensing, and certification requirements at both state and federal levels.
This section has been divided into-four phases of oil and gas operations,
designated the Pre-lease, Exploration, Field Development, and Production
stages. Where one permit might be required in more than one p hase, it has
been listed under the phase in which it first becomes necessary.

I. Legislation

A. Laws Concerning Environmental Protection

1. Water Quality

Several pieces of federal and state legislation deal specifically with
the prevention and control of water pollution, both from regular discharges of
noxious materials.and from oil spills. The Federal Water Pollution Control
Act (FWPCA), 33 U.S.C. �1251 et seq., establishes effluent standards and
provides for Coast Guard enforcement of the standards. Under this authority
the Coast Guard enforces the prohibitions against oil and oily waste dis-
charges by conducting pollution and surveillance patrols. 01321)

Amendments to the FWPCA in 1972 created the National Pollutant Discharge
Elimination System (NPDES), which applies to any project resulting in dis-
charges to surface waters in territorial seas, including the three-mile zone,
the contiguous zone, and oceans. Under NPDES, EPA permits (now administered
by the N.C. Division of Environmental Management) are required for discharges
from fixed platforms and drillships, including both gradual and bulk dis-
charges of drilling muds. Under the procedures and criteria for NPDES
permits, the activity being permitted may cause "no unreasonable degradation
of the marine environment."l Also required under the 1972 amendments are:

140 CPR 125.122 et seq.

E-1

Coast Guard approval of procedures and equipment for transferring oil;2
certification that discharges are in compliance with state water quality
standards;3 and permits for the discharge of dredge and fill materials into
U.S. waters.4 For more information on these permits, see Part II, "Permit-
ting, Licensing, and Certification."

The North Carolina Oil Pollution and Hazardous Substance Control Act of
1978 (N.C. Gen. Stat. �143-215.75 et seq.) is a follow-up measure to the FWPCA
1972 amendments. It is not meant to apply where there is exclusive federal
jurisdiction, but rather to "support and complement" applicable federal laws.
The Act's stated purpose is to promote the health, safety, and welfare of
North Carolina citizens by protecting land and water under state jurisdiction
from pollution by oil, oil products, oil by-products, and other hazardous
substances. To accomplish this purpose, it mandates the establishment of an
oil pollution control program under the Department of Natural Resources and
Community Development (NRCD). The control measures include permits for the
discharge of oil, permits for refining facilities, registration of oil
terminal facilities, and immediate clean-up of damages by those "having
control over" discharges which damage property and/or injure wildlife, fish,
or natural resources.

There are several other pieces of legislation dealing with water pollu-
tion and conservation. A federal act relating to prevention of pollution from
ships was codified in 1980 at 33 U.S.C. �1901. The act supersedes, in part,
.the Oil Pollution Act of 1961, and mandates Coast Guard enforcement of the
MARPOL Protocol of 1978, which resulted from the International Convention for
the Prevention of Pollution from Ships of 1978. The act requires certificates
of adequacy of port or terminal facilities for the transfer of oil or noxious
liquids.

Miscellaneous provisions under Title 143, Article 21, of the North
Carolina General Statutes (N.C. Gen. Stat. �143-211 et seq.) establish state
policy on air and water conservation and create the Environmental Management
Commission (EMC) to administer pollution control and water resources manage-
ment programs. These statutes prohibit the discharge of wastes into ocean
waters under North Carolina jurisdiction except where EMC regulations permit
it 5 rohibit discharge of waste to subsurface or groundwaters by means of a
weil ,9 and require a permit from EMC for the discharge of any waste, directly
or indirectly, in violation of applicable water quality standards.7 The Water

233 U.S.C. �1342.

333 U.S.C. �1341; �401 of the 1972 Act.
433 U.S.C. �1344; 5404 of the 1972 Act.

.5N.C. Gen. Stat. �143-215.2(c).

6N.C. Gen. Stat. �143-214.1(b).
7N.C. Gen. Stat. �143-214.1 et seq., and -215.1 et seq.

E-2

Use Act of 1967 (N.C. Gen. Stat. 6143-215.11-.22) sets state policy for water
conservation. It requires the issuance of water use permits from the EMC for
large projects in specified "capacity use areas." Although the single desig-
nated capacity use area includes a large portion of the coastal plain, most,
oil and gas operations, at least prior to the field development stage, will
not use enough water to require a permit. Additionally, under the Water
and Air Quality Reporting Act of 1971 (N.C. Gen. Stat. �143-215.63) all
persons subject to EMC water pollution regulations are required to file
reports on discharges to EMC at least quarterly. State legislation also
enables local governments to have ordinances and regulations regarding the
control of oil pollution (N.C. Gen. Stat. �143-215.82).

To mitigate the damage caused by oil spills, the federal Clean Water Act,
incorporated into FWPCA at 33 U.S.C. �1321, holds the owner or operator of any
vessel or facility liable for the costs of removing spills of oil or hazardous
substances attributable to that vessel or facility. In addition, other
penalties may be charged. Under the Act, the Council on Environmental Quality
prepared a National Contingency Plan for the removal of oil and haz ardous
substances and an emergency procedure for preventing the adverse effects of
oil spills.

The Comprehensive Environmental Response, Compensation and Liability Act
of 1980 (CERCLA), 42 U.S.C. �9605, charged the Environmental Protection
Agency with revising the National Contingency Plan. This revised plan, the
National Oil and Hazardous Substances Pollution Contingency Plan, at 40 CFR
300, coordinates the actions of the federal government in the efficient
control and clean-up of spills and encourages state and local governments to
develop plans consistent with the federal one.

In 1981, North Carolina adopted its Hazardous Materials Emergency
Response Plan as mandated under the Water and Air Quality Reporting Act, the
Oil Pollution and Hazardous Substances Control Act of 1978, and the Air and
Water Pollution Control Act, and as urged by the National Contingency Plan.
The State plan establishes the duties of all involved state agencies in
responding to hazardous materials emergencies, including oil spills, in the
State of North Carolina. The Division of Environmental Management in NRCD is
primarily responsible for coordinating spill containment and clean up and
taking action against the perpetrators of unlawful spills.

2. Air Quality

Although offshore oil and gas drilling may not immediately evoke thoughts
of air pollution, emissions from a variety of sources do occur and will be
governed by both state and federal legislation. The major piece of federal
legislation is the Federal Clean Air Act (42 U.S.C. �7401 et seq.). This act
allows the transfer of air quality permitting authority to the state, with EPA
oversight, once a State Implementation Plan has been approved, as North
Carolina's has.8 The Act establishes a set of National Ambient Air Quality
Standards (NAAQS), which set the maximum acceptable levels for a number of
common pollutants. If a new source of air pollution is located in an

840 CFR 42.1772.

E-3

"attainment area" (i.e., one meeting NAAQS, as do all North Carolina coastal
counties) and if it will emit more than 250 tons/year of a regulated pollutant
.(or 100 tons/year if it is one of a select number of industrial facilities,
including oil storage terminals with capacity greater than 500,000 barrels and
oil refineries) it is required to obtain a Prevention of Significant
Deterioration of Air Quality (PSD) permit before commencing construction,
showing that the pollution controls used will be the "best available control
technology."

Similarly, under Title 143, Article 21B of the North Carolina General
Statutes, the state government has set up a process of state air quality
controls and permitting, administered by the Division of Environmental Manage-
ment (DEM). DEM is charged with responsibility for the adoption of air
quality standards, emission control standards, and classification of air
contaminant sources, and with oversight of local air pollution control
programs.9 The controlling legislation also requires an EMC permit for the
The controlling legislation also requires an EMC permit for the construction
or operation of any air contaminant source or polluting equipment. (More
information on these permits is included in Part II of this Appendix.)

3. Coastal Resources

The Federal Coastal Zone Management Act of 1972, 16 U.S.C. �1451, estab-
lishes a national policy for the protection of coastal areas and encourages
planning and management at local and state levels. Once a state has a
federally approved coastal zone management program, as does North Carolina,
any federal actions in a coastal area, including licenses and permits, must be
certified by the state as consistent with the state's coastal program.10 When
the applicant for a permit determines that the proposed activity meets the
state requirements, he declares this in the application and forwards the
application to the state, which has its own internal process for comment and
approval.11

The North Carolina Coastal Area Management Act of 1974 (CAMA; N.C. Gen.
Stat. �113A-100 - �113A-128) calls for a comprehensive state planning and
management program to protect public interests unique to the coastal zone and
to "ensure the orderly and balanced use' and preservation of our coastal
resources on behalf of North Carolina and the nation." Under the program
established, a permit is required from the state for "major developments" in
"Areas of Environmental Concern" (AEC). Oil and gas drilling is by definition
a major development, and all submerged lands fall into one or more categories
of AECs. The Act also provides for locally-approved "minor development"
permits for certain activities and requires coastal towns and counties to
develop land use plans. Under Executive Order #15 of Governor Hunt, "all
state agencies shall take account of and be consistent to the maximum extent

9N.C. Gen. Stat. �143-215.105 et seq.

.1016 U.S.C. �1456(e)(3).

1115 CFR 930-D.

E-4

possible with" North Carolina coastal policy and must consult and coordinate
their activities with the Coastal Resources Commission.

4. Other Environmental Concerns

Two other topics of concern are soil conservation and protection of fish
and wildlife. Under the North Carolina Sedimentation Pollution Control Act of
1973 (N.C. Gen. Stat. �113A-50 - �113A-66) the Sedimentation Control Comnis-
sion was charged with setting up an erosion and sedimentation control program.
Under this program, every developer must file a sedimentation control plan
with the Division of Land Resources in NRCD for any change to the natural
cover or topography which might cause or contribute to sedimentation on a lot
of one acre or more. Local governments may supersede the state law with
erosion control ordinances at least as stringent as the state's. Major
onshore facilities associated with offshore drilling will be subject to the
requirements of this statute.

Both the federal and North Carolina legislatures have enacted laws for
the protection.of fish and wildlife. The Endangered Species Act of 1973, 16
U.S.C. �1531, requires every federal department or agency, in consultation
with the Secretary of the Interior, to insure that none of its actions
(including permitting) jeopardizes any listed species. Jurisdiction over the
various species is divided between the U.S. Fish and Wildlife Service and the
National Marine Fisheries Service. The Federal Fish and Wildlife Coordination
Act (16 U.S.C. �661 et seq.) requires "that wildlife conservation shall
receive equal consideration and be coordinated with other features of water-
resource development programs." To ensure that this is done, the Act requires
the project agency to consult with the U.S. Fish and Wildlife Service, and in
North Carolina the Wildlife Resources Commission, before any federal licensing
in streams or other bodies of water. Although it is unlikely to apply to off-
shore drilling, the Marine Mammal Protection Act, 16 U.S.C. �1361, makes it
illegal for any person, vessel, or conveyance to "take" any mammal in waters
under U.S. jurisdiction, unless under a restricted permit from the Secretary
of the Interior or the National Oceanic and Atmospheric Administration.
"Taking" includes harassing, hunting, capturing, killing, or attempting to do
SO.

In the state's territorial waters, the North Carolina Marine Fisheries
Commission (MFC), under NRCD, has jurisdiction over the conservation of
marine and estuarine resources. Although the relevant legislation, N.C. Gen.
Stat. �113-127 et seq., applies primarily to commercial fishing operations,
the MFC is consulted when permits for excavation or filling in coastal areas
are granted and is required to conduct public hearings if objections to these
permits are filed (N.C. Gen. Stat. �113-229). The MFC regulations have super-
seded most local regulation of marine and estuarine resources, but MFC has no
jurisdiction over matters which ate clearly under the control of the Depart-
ment of Agriculture, the N.C. Pesticide Board, the Commission for Health
Services, the EMC, or any other NRCD division regulating air or water
pollution (N.C. Gen. Stat. ��113-133, 133.1, 132(c)).

E-5

D. Laws Concerning Navigation and Construction

The primary piece of legislation regarding navigational safety is the
U.S. Ports and Waterways Safety Act (33 U.S.C. ��1221-1232). This act gives
the U.S. Coast Guard primary responsibility for port and navigational
safety, including control of traffic flow (timing and routing of vessels),
procedures and safeguards for handling cargo, and minimum safety equipment for
structures. Pursuant to the Act, dozens of regulations have been issued
regarding general permits for handlinf dangerous cargo such as liquid petro-
leum gas (LPG) and crude oil at port; 2 Coast Guard direction of moving or
loading oil.on sea structures or at port,13 providing notice of hazardous con-
ditions on board exploratory vessels,14 bulk carrying of hazardous or flam-
mable cargo 15 labelling of hazardous substances, including crude oil and LPG,
in transit,16 and the certification of non-bulk (containerized) shipment.17

State statutes at N.C. Gen. Stat. �76-40 also regulate certain practices
in navigable waters under state jurisdiction.. Among these laws are the pro-
hibition of trash, refuse, or scrap in navigable waters, the requirements for
obtaining construction permits and for removing structures within 30 days of
abandonment, the jurisdiction of NRCD and EMC to enforce the Act in coastal
waters, and other provisions relating to specific coastal areas.

Several state and federal laws deal with construction activities in
coastal areas, several of which are discussed in greater detail in Part II of
this chapter. The primary federal act under this topic is the Rivers and
Harbors Act of 1899 (33 U.S.C. �401 et seq.), which is applicable to any con-
struction of new harbors or structures which might obstruct navigable waters.
A permit is required from the Army Corps of Engineers for all offshore
construction or work in U.S. navigable waters.

The North Carolina Dredge and Fill Act (N.C. Gen. Stat. S�113-229)
requires a permit from the Office of Coastal Management for any dredging and
filling in estuarine waters, tidelands, and other waters, including the three-
mile zone. For construction of drilling rigs, support bases, terminals,
refineries or other structures needed at various stages of oil and gas
activities both onshore and off,18 local land use regulations and construc tion
codes must also be considered.

1233 CFR 126.27.

1333 CFR 160.106.

1433 CFR 161.1.

1533 CFR 153, 154.

1649 CFR 172.101.

1749 CFR 176.27, .5.
18Counties may now regulate development over estuarine waters and lands
covered by navigable waters owned by the State, by an Act of the General
Assembly in 1983, amending N.C. Gen. Stat. �153A-340.

E-6

C. Laws Concerning Business and Employment Practices

As with any business venture, oil and gas development must meet some
general prerequisites for conducting business, as established by state and
federal law. While most of these considerations are generally applicable to
all businesses, such as wage and hour laws and social security, other laws
.may apply more particularly to offshore oil and gas drilling. These include
provisions related to occupational health and safety, certain pricing
controls, and special tax provisions.

Since the working conditions on oil rigs are among the most hazardous
anywhere, occupational safety and health is a major concern to any company
conducting oil and gas drilling activities. The Federal Occupational Safety
and Health Act of 1970 (OSHA; 29 U.S.C. ��651-678) applies to workers and
workplaces in all states, but �653 excludes working conditions where "other
Federal agencies . . . exercise statutory authority to prescribe or enforce
standards or regulations affecting occupational safety or health." While
Coast Guard occupational safety regulations supersede OSHA they apply only to
Outer Continental Shelf areas and not the three-mile zone.fg However, some
Coast Guard safety regulations regarding inspection of design, equipment,
operations and stability of mobile offshore drilling units are not limited to
OCS rigs.26

The court cases questioning whether OSHA is superseded by other laws
have, to some extent, delineated what OSHA does and does not cover. One case
says that "offshore platforms" (with no differentiation between those in
federal and state waters) are under Department of Interior and Coast
Guard control, so OSHA is not applicable.21 Similarly, those companies
included under the safety regulations of the Natural Gas Pipeline Safety Act
of 1968 are exempted from OSHA. Another case states that the Coast Guard has
authority over "seamen," but not over onshore workers such as longshoremen.22
A final case elaborates that non--seafaring offshore activities, such a ship
repair, do fall under OSHA regulations.23

The Occupational Safety and Health Act of North Carolina (OSHANC, N.C.
Gen. Stat. �95-126 et seq.) includes by reference all OSHA provisions and is
applicable to most employers and employees in the state. Among those excepted
are those protected under the Metal and Non-metallic Mine Safety Act (not
applicable to offshore drilling) and those engaged in "maritime operations."
State OSHA jurisdiction, according.to North Carolina officials, "ends at the

1933 CFR 142 - 174.15.

2046 CFR 107.

21Marshall v. Nichols, 486 F. Supp. 615 (e.d. Texas, 1980).
22Taylor v. Moore-McCormack Lines, Inc., 629 F.2d 88 (4th Cir., 1980);
T. Smith & Son) Inc., OSHRC Docket No. 2240, 1974-1975, CCH OSHD 118536
(1974).

23Petrolane Offshore Construction Services, Inc., OSHRC Docket No. 2361,
1974-1975, CCH OSHD 119600, 3 BNA OSHC 1156 (1975).

E-7

docks," and therefore does not cover offshore activities. According to
federal OSHA officials, however, the state has jurisdiction but may defer to
the Coast Guard for occupational safety and health in territorial waters; the
Coast Guard can, in turn, defer to the federal OSHA administrators, on a case-
by-case basis.

Although price regulations vary with the political climate, they are
important for a business to look at in determining whether its operations will
'be profitable. The Natural Gas Policy Act (15 U.S.C. 63301 et seq.) sets
ceiling prices for natural gas from the OCS, from onshore wells, and for use
in interstate commerce, among other situations. These price controls are
administered by the Federal Energy Regulatory Commission with supporting
regulations published at 18 CFR 270 et seq.

Taxation is among the most important considerations of any business.
Both federal and state corporate income taxes apply to oil drilling within
state waters, and local property taxes apply to onshore support activities,
though these taxes are not likely to extend into the water. Under the
the North Carolina Income Tax Act of 1939 (N.C. Gen. Stat. �105-130 et seq.)
every North Carolina corporation or corporation doing business in North
Carolina is subject to a 6 percent tax on net income. Deductions possibly
applicable to oil and gas drilling include one for the cost of air cleaning
devices, waste treatment facilities, pollution abatement equipment, and the
recycling of or resource recovery from solid waste,24 and one for the use of
equipment mandated by OSH.A.25 In addition to income taxes, NRCD is authorized
to assess against each barrel of crude oil extracted a tax of up to five mills
and against each 1000 cubic feet of natural gas produced, a tax of up to one-
half mill, to cover the costs of administering and enforcing the Oil and Gas
Conservation Act.

D. Laws Concerning Historic and Cultural Preservation

Oil and gas operators drilling in submerged lands may uncover or disturb
objects or sites of historical or scientific significance during exploration
and development operations. Such finds could include shipwrecks or sites
occupied during prehistoric or historic times and since inundated by rising
sea levels. Both state and federal laws have been enacted to protect these
resources.

Under the National Historic Preservation'Act of 1966 (16 U.S.C. �470),
the head of any federal department or agency with jurisdiction over or
authority to license "a proposed federal or federally assisted undertaking in
any State" must, before federal money is spent or a license is issued, "take
into account the effect of the undertaking on any district, site, building,
structure, or object that is included or eligible for inclusion in the
National Register [of Historic Places]." Although only one site within North
Carolina waters is listed in the National Register (the U.S.S. Peterhoff near
Cape Fear), the criteria for eligibility are rather broad. To be eligible,

24N.C. Gen. Stat. �105-130.10.

25N.C. Gen. Stat. �105-130.10A

E-8

places may be associated with significant historical events or figures,
reflect distinctive characteristics of a particular type or period of archi-
tecture or artistic values, or be likely to yield important information on
prehistory or history.26

Similarly, under N.C. Gen. Stat. �121-12(a), every state agency must
consider the effect of any undertaking, including licensing, approval, and
authorization, on any site, structure, or object listed in the National
Register. If there is any likely effect, the Historical Commission must be
given a reasonable opportunity to comment. This statute, unlike its federal
counterpart, is limited to those places listed in the Register and does not
extend to eligible sites.

N.C. Gen. Stat. S121-22 to �121-28 deals with the salvaging of abandoned
shipwrecks and other underwater archaeological sites. The Act vests title to
and exclusive dominion and control over all bottoms of navigable waters one
marine league (three nautical miles) seaward of extreme low water mark, and
all shipwrecks, vessels, and other sea bottom archaeological artifacts
unclaimed for over ten years, in the State of North Carolina. The Department
of Cultural Resources is custodian of all such vessels, wrecks, and artifacts
and is authorized to issue necessary rules and regulations to preserve,
protect, recover, and salvage them; these supporting regulations have been
promulgated at 7 NCAC 4J.

II. Permitting, Licensing, and Certification

Offshore oil and gas operations can be divided into four phases. During
the first phase, Pre-leasing, geological and geophysical exploration is con-
ducted and measures necessary to acquire a lease for submerged lands may be
taken. Once the land has been leased, exploratory drilling, the second phase,
commences. If exploratory drilling indicates the presence of commercially
sufficient quantities of oil and/or gas, the third stage, Field Development,
is undertaken. During this phase, permanent drilling and/or production plat-
forms are built, wells are drilled, and pipelines are laid. After the field
has been so prepared, the fourth stage, Production, begins.

The purpose of this section is to list and describe the permits required
at each stage and the procedures necessary for obtaining those permits. Since
some permits may be required at more than one phase and some may not be re-
quired at all, these permits have been categorized as "probable" and "pos-
sible" and are listed at the first stage where they might be required. (A
tabular description of necessary permits can be found in Table 3-2, at the end
of Chapter 3.) Finally, it is important to keep in mind such regulations as
the Coast Guard Navigational Safety Standards which are applicable but for
which no actual permitting is required.

2636 CFR 60.4.

E-9

A. Phase I- Pre-lease

The following permits or approvals are currently required before
preliminary exploration begins and/or before a lease is granted:

1. North Carolina Geophysical Exploration Permit (possible)
N.C. den. Stat. �113.27; 15 NCAC 5C

This permit, issued by the Division of Land Resources in the Department
of Natural Resources and Community Development, is required for all seismic
exploration involving the use of explosives. To obtain the permit, a surety
bond of $5,000 for one crew or $25,000 for more than one crew must be filed.
The Wildlife Resources Commission, the Division of Marine Resources, and
the Office of Coastal Management must have an opportunity to review the appli-
cation. In addition, each crew must be accompanied by a State seismic agent
who files a daily report. NRCD, on request, may have access to all records of
the explorers, but "only to the extent necessary to determine that all protec--
tive requirements have been complied with."

2. Environmental Impact Assessment (EIA) (possible)
N.C. Gen. Stat. �143B-437

This statute, administered by the Department of Commerce in collaboration
with NRCD, requires an assessment of the effects of any new or expanding
industry or manufacturing.plant on the economic and natural environment of the
state. Such assessments, rarely prepared in the past, may be used more often
where other environmental impact statements are not required or where the
political atmosphere dictates it.

B. Phase II. Exploration

After the land is leased, field exploration is conducted with test drill-
ing to identify potentialreservoirs of oil and gas and determine whether it
is commercially possible to produce them. The work requires the construction
of temporary offshore platforms and small temporary onshore support facili-
ties. The principal environmental effects of these operations were reviewed
in Appendix D; they include the dredging and/or filling of access routes, rig
discharges, and the risk of oil pollution.

.'Several of the permits listed here as "possible" are dependent upon the
amount of onshore activity accompanying the exploration.. Usually land
operations, construction and employment are kept at minimal levels at this
phase, so many of these permits are not likely to be required in most explo-
ration situations. They are more likely to be required at the Development and
Production stages when onshore activity intensifies. The permits applicable
to the Exploration stage are as follows:

E-10

1. Coastal Area Management Act (CAMA) Major Development Permit
(required)
N.C. Gen. Stat. �113A-100 - �113A-128; 15 NCAC 7H, 7J, 7M

CAMA Major Development Permit will be required before exploratory
drilling begins. It is granted by the Office of Coastal Management (OCM) and
required for any development in an "Area of Environmental Concern" (AEC) if
the activity:

a. requires permission, licensing, approval, certification, or
authorization from the Environmental Management Commission,
Mining Control Board, Department of Human Resources, Department
of Natural Resources and Community Development, or Department of.
Administration;

b. occupies an area in excess of 20 acres;

c. contemplates drilling or excavating for naturalresources; or,

d. contains a structure(s) covering a ground area of over 600,000
square feet..

AECs have been defined to include:

a. parts of the estuarine system, including estuarine waters,
coastal wetlands, public trust areas, and estuarine shorelines;

b. ocean hazard areas;

c. public water supplies; and

d. natural and cultural resource areas.

To apply for a CAMA Major Development Permit, an application must be
submitted to OCM describingthe location and type of project, the expected
type and area of disposal, construction equipment used, the current and future
use of the project area, a specific location map and work plat, and a copy of
the deed, lease, or permitto use.

The process for evaluation of requests includes review and comment by
.appropriate agencies and public notice and comment. The Coastal Resources
@Commission makes the final decision whether to approve the application based
on:

a. the state guidelines for actions in AECs promulgated under CAMA,
which require that permitted activities cannot:

1. be contrary to coastal management objectives;
2. present any suitable alternative;
3. violate air or water quality standards;
4. present any major or irreversible damage to historic
or cultural resources;
5. measurably increase siltation;

E-11

6. create stagnant water bodies;
7. be timed so as to have greater than minimal adverse effect
. on estuarine life;
8. block navigation; or
9. be inconsistent with the ocean hazard system described at
15 NCAC 7H .300.
(15 NCAC 7H .0208)

b. local land use plans;

c. general policy guidelines for the coastal area, listed in
15 NCAC 7M, and including:

1. Local governments should not unreasonably restrict necessary
energy development, but should develop siting measures to
minimize impacts on resources.

2. Impact assessment is required before construction of a "major
energy facility," which includes refining facilities,
pipelines, and terminal and storage facilities.

d. other criteria listed in N.C. Gen. Stat. �113A-120 et seq.
,(including, by reference, �113-229 and �113-230)

The CAMA Major Development Application also serves as a consolidated applica-
tion for the �10, �404, North Carolina Easement to Fill, and North Carolina
�401 Water Quality Certification permits (all described below).

2. National Pollution Discharge Elimination System (NPDES) Permit
33 U.S.C. �1342; 40 CFR 125.122 et seq.; 15 NCAC 2H .0100. (probable)

This permit is required by the federal Environmental Protection Agency
and administered by the North Carolina Division of Environmental Management
for point source discharges of drilling muds, industrial wastewater, or
domestic sewage from fixed platforms and drillships. To apply, the operator
must file with DEM an environmental assessment containing descriptions of:

a. the proposed new source of discharge;
b. alternative treatment or other control measures;
c. primary and secondary environmental impacts;
d. unavoidable adverse impacts and mitigative measures to
address adverse impacts; and
e. irreversible and irretrievable commitments of aquatic
resources*

DEM reviews the application and forwards it for EPA approval. Public notice
and a 30-day period for comments are required, with a decision on approval or
denial within 90 days. The key question is whether there is any "unreasonable
degradation of the marine environment."

E-12

3. Section 401 Water Quality Certification
33 U.S.C. �1341; 15 NCAC 2H .0500 (probable)

This certification by the Division of Environmental Management is
required of federally licensed projects with discharges into state waters, to
assure that state water quality standards will be met before a federal license
or permit is given. The applicant must file.with DEM six copies of the
following information, to be circulated to the appropriate agencies for
comment:

a. a description of the activity;
b. the water discharge that is occurring or proposed;
C. the location of the discharge;
d. a description of the receiving waters;
e. a description of waste treatment facilities, if any; and
f. the names and addresses of adjoining riparian owners.

After a public notice and comment period and possibly a public hearing, the
final decision is made by the Environmental Management Commission within 130
days of the application or the hearing.

4. Permit to Drill Exploratory Oil or Gas Wells
N.C. Gen. Stat. �.113-27; 15 NCAC 50 (required)

This permit is required before the drilling of an oil and gas well so
that certain regulations regarding well spacing, drilling conduct, protection
of groundwater strata, casing, well direction, blowout prevention, plugging,
production limits, and abandonment can be met. The.permit application must be
filed with the Division of Land Resources in NRCD, along with the following
information:

a. the total depth of the well;
b. the casing program;
c. proposed boring disposal program;
d. well name, number, and location;
e. proof of ownership or leasehold in lands to be drilled;
f. statement of liability for violation of rules; and
g. $50 fee

Permits are usually issued within 30 days. Before drilling exploratory wells,
however, the operator must file a $5,000 bond with NRCD to assure proper
plugging of the well.

5. Section 10 Permit for Construction Affecting U.S. Navigable Waters
33 U.S.C. 5401 et seq. (required)

This permit from the U.S. Army Corps of Engineers is required for
any excavation, dredging, or dispersal, or the construction of any structure
or other impediment to navigation in U.S. navigable waters. In reviewing
applications for permits, the Corps consults with affected agencies and
considers the effects of the project on:

E-13

a. the public interest;
b. wetlands;
c. fish and wildlife;
d. water quality; and
e. historic, scenic, and recreational values

Section 10 permits are usually considered together with Section 404
permits and may be granted automatically if State Dredge and Fill, CAMA, and
Section 401 permits are issued.

6. �404 Permit (probable)
33 U.S.C. �1251, �1344; 40 CFR 235

This permit, administered by the Corps, is required for any discharge of
dredge and fill materials into navigable waters. Public notice and an oppor-
tunity for a public hearing are required. The �404 permit is usually con-
sidered together with the �10 permit and many of the same environmental
standards are applied in the review of both.

7. State Air Quality Permit (probable)
N.C. Gen. Stat. %143-215.108;. 15 NCAC 2D, 2H (including national
emissions standards for hazardous pollutants)

Issued by the Division of Environmental Management, these permits are
required fort

a. establishing or operating any air contaminant source for which
there is an applicable air quality or emission control standard
at 15 NCAC 2D or 2H. Such sources include hydrocarbons stored in
certain quantities under certain conditions, and may include
temporary onshore support bases which store fuel;

b. constructing, operating, or using any equipment which might emit
air contaminants or cause air pollution; or,

c. constructing or installing any air-cleaning device.

Along with a permit application, detailed engineering plans and specifications
are required.

8. Prevention of Significant Deterioration (PSD) Permit (possible)
42 USC �7401 et seq.; 40 CYR 52.21(b)(1)

These permits are administered by the Division of Environmental Manage-
ment with EPA approval. A permit is required for any new source of air pol-
lution which is located in areas, such as North Carolina coastal counties,
which meet National Ambient Air Quality Standards and which:

a. will emit more than 100 tons per year of a regulated pollutant
and is among the sources listed in 40 CFR 52.21(b)(1). (These
include oil refineries and petroleum storage units with a

B-14

capacity of 300,000 barrels or more; if these'facilities are
built at all, it will be during field development);

b. is not listed, but will emit over 250 tons per year
of a regulated pollutant.

PSD permits may be processed along with State,Air Quality permits (15 NCAC
2H. 0600).

9. Certification of Mobile Offshore Drilling Units (probable)
46 CFR 107

This regulation requires a certification for safety by the Coast Guard
for any mobile offshore drilling units. The Coast Guard has issued
detailed safety standards applicable to the design, equipment, operations, and
stability of drilling units.

10. State Dredge and Fill Permit (probable)
N.C. Gen. Stat. 5113-229; 15 NCAC 7J .0800-.1024

This permit is required for any project involving dredging and filling in
estuarine waters, tidelands, marshlands, or state-owned lakes. Most oil and
gas development in the sounds will require dredging and filling to prepare
and maintain access to the drill site.

Along with the official permit form, a work plat detailing the proposed
construction and mapping its location must be submitted to the Office of
Coastal Management. After riparian landowners are given 30 days to comment,
there is an on-site investigation and report on the project. All of this
information is then circulated to interested state agencies and back for an
NRCD decision within 90 days. The permit application automatically includes a
request for a CAMA Major Development Permit, Corps Sections 10 and 404
permits, an Easement to Fill on State-owned Land, and 401 Water Quality
Certification, if they are required. A general permit is issued if the state
requirements aremet and there are no objections submitted by federal
agencies.

11. North Carolina Easement to Fill (possible)
N.C. Gen* Stat. �146-2; 1 NCAC 6B .0500-.0512

This easement will be required if any construction requires filling
activities in waters where land is raised above the normal high water mark.
At the exploration phase, such construction is unlikely; however, when more
onshore facilities are required for support of development and production
activities, this easement will more likely be required. Since this filling
activity is a real estate action, allowing the alteration and use of state
submerged lands, it is administered by the State Property Office in the
Department of Administration.

It has become the Department of Administration's practice in recent years
to issue these easements only under extraordinary circumstances. Requests to

E-15

fill in lands removed by erosion during the previous year are generally
approved without an easement, while requests to fill larger areas are
generally denied.

12. U.S. Environmental Impact Statement (EIS) (probable)
42 U.S.C. �4332; 40 CFR 1500-1508.

An EIS is prepared by the lead agency in federal permitting and is
required for any action under federal control and responsibility "signifi-
cantly affecting the quality of the human environment." Activities which
require federal permits or licenses are considered to be federal actions for
EIS purposes; however, those merely requiring federal review are not. The EIS
must go through a public and government comment process and must contain a
discussion of:

a. the environmental impact of the proposed action;
b. the adverse environmental effects that would be unavoidable
if the proposal is implemented;
c. alternatives to the proposed action;
d. the relationship between local short-term uses of man's
environment and the maintenance and enhancement of long-term
productivity; and
e. any irreversible and irretrievable commitments of resources which
would be involved if the proposed action is implemented.

The Corps of Engineers, by virtue of its �10 and �404 permits, would
probably act as lead agency and produce the EIS. In Alabama, for instance,
the Corps filed separate, sequential EIS's for the initial exploratory wells,
for the four additional appraisal wells, and for field development and pro-
duction in the Lower Mobile Bay gas field discovered and developed by Mobil.

13. State Environmental Impact Statement (SEIS) (possible)
N.C. Gen. Stat. �113A-4; 1 NCAC 25

A state Environmental Impact Statement, under present law, is required
for any proposed legislation or activities "involving expenditure of public
moneys for projects and programs significantly affecting the quality of the
environment" of North Carolina. Exactly what "public moneys" are has been a
subject of dispute; it has been held to include federal and local funds, as
well as state funds, but the administrative rules have not been updated to
clarify the criteria. Since offshore exploration and drilling do not require
state expenditure beyond those costs incidental to permitting and licensing
activities, an SEIS may not be necessary. See the discussion of impact
statements and SEPA in Chapter 5.

14. Environmental Impact Assessment (possible)
(see Phase 1)

E-16

15. Permit for Wastewater Not Discharged to Surface Waters (possible)
N.C. Gen. Stat. �143-215.3; 15 NCAC 2H

This permit, administered by the Division of Environmental Management
(DEM), is required for sewer systems, treatment works, or disposal systems
which have over a 3,000 gallon capacity and do not discharge into surface
waters. Depending on the amount of waste generated and the type of disposal
system used, this may or may not be required. The application submitted,
along with design data, specifications and plan information, is assessed by
DEM after on7site review by its Water Quality and Ground Water Sections.

16. Solid Waste Disposal Site Permit (possible)
N.C. Gen. Stat. �130-13B; 10 NCAC 10C

This,permit, administered by the Division of Health Services (DHS) in the
Department of Human Resources, is required for establishing and operating
solid waste disposal facilities and incinerators. To obtain a permit, maps,
plans, land ownership and use information, proposed operation procedures and
methods, and expected waste generation data must be submitted to DHS.

17. Hazardous Waste Permit (possible)
N.C. Gen. Stat. S130-13B; 10 NCAC 1OF; 40 CFR 260.1-265

This permit, administered by the Department of Human Resources, is
required for treatment,.storage, or disposal of listed hazardous wastes in
North Carolina, including gas and oil drilling muds and oil production brines;
most federal regulations concerning hazardous wastes have been adopted by
North Carolina. (Non-solid toxic emissions are covered by air and water
pollution control regulations and NIPDES.) A permit application must include
general information about the facility and the company operating it, manage-
ment processes, operating procedures, security, inspection, contingency plans,
and disaster mitigation. After public notice and comment, and possibly a
public hearing, a decision is reached within 90 days.

18. Sedimentation Control Plans (possible)
N.C. Gen. Stat. �113A-50 - �113A-66; 15 NCAC 4

This program has been implemented to reduce the effects of sedimentation
in the state's waters and to control accelerated erosion resulting from land-
disturbing activities. Thirty days before initiating any land-disturbing
activity on a tract of one or more acres, a sedimentation control plan must be
filed with the Division of Land Resources. Plans must include architectural
and engineering drawings, maps, calculations, assumptions and narrative
descriptions of the necessary erosion reduction and sedimentation control
structures and devices. Under the act, local governments may take over
administration of the program by enacting erosion control ordinances whose
standards equal or exceed those of the state.

E-17

19. Tax Certification for Resource Recovery,Recycling, or Pollution
Abatement Facilities (possible)
N.C. Gen. Stat. �130-13B, �105-130.10; 10 NCAC 10C .0500

In order to obtain the special tax benefits of installing these
facilities, a company must be inspected and certified by the Department of
Human Resources.

20. Burning Permits (possible)
N.C. Gen. Stat. 5113-60.21 to �113-60.31; 15 NCAC 9C .0200

These permits, administered by the Division of Forest Resources, are
required for certain types of burning related to land clearing activities,
particularly in coastal counties. The applicant must also meet any applicable
DEM conditions for open burning. These permits can be obtained from the
county or district forest rangers.

21. Open Burning Permit (possible)
N.C. Gen. Stat. �143-215.3; 15 NCAC 2D .0520

This permit, obtained from the Division of Environmental Management, is
required for all activities involving open burning, unless specifically
exempted. Special permits are required for burning windrows in Beaufort,
Bertie, Camden, Carteret, Chowan, Currituck, Dare, Gates, Hyde, Pasquotank,
Perquimans, Tyrell, and Washington counties. Application information is
provided by the forest ranger when applying for the DFR burning permit
(above).

D. Phase III. Field Development

After exploratory drilling has indicated the presence of commercial
quantities of oil or gas, the field may be prepared for production. During
this stage, drilling will continue, and the laying of pipelines, the construc-
tion of permanent platforms and wells, and the acceleration of onshore support
activities usually also occur. Onshore activities at this stage are likely to
include,, to some extent,- fabrication of pipe and platforms, pipe coating, and
the construction of processing facilities, terminals, and refineries, some or
all of which will likely require shoreline clearing, dredging, or construc-
tion. Some of these uses and activities, such as oil terminals and the laying
of pipelines, will occur offshore as well.

With this increased activity come new or increased environmental hazards.
In addition to many of the permits mentioned under Phase II above, the follow-
ing permits may be required:

1. Water Use Permit (possible)
N.C. Gen. Stat. �143-215.11-.22; 15 NCAC 2E

In areas designated as 11 capacity use areas" by the Environmental Manage-
ment Commission (EMC), which include a large portion of coastal North

E-18

Carolina, these permits are required for withdrawals of surface water and
groundwater in excess of 100,000 gallons of water per day. An applicant for a
water use permit must submit an official form to DEM before project initiation
and must specify the proposed uses of the water and give some justification
for the quantity needed. Processing of the permit, which involves notifica-
tion of other permit holders if the use is consumptive, usually takes about 30
days. Users are also subject to requirements regarding well-spacing, water
level controls, and reporting.

2. Easements Over Water (probable)
N.C. Gen. Stat. �146-11 et seq.; 1 NCAC 6B .0600-.0610

Easements may be granted for structures over or in navigable waters,
including pipelines, which are built to utilize the state's natural resources.
A written application must be filed with the State Property Office, with a
plat or drawing of the proposed project and a $100 fee. Applications,
which require approval by the Governor and Council of State, are normally
processed within 45 to 60 days.

3. Oil Terminal Facility Certificate of Registration (probable)
N.C. Gen. Stat. �143-215.95 - .98

This permit, administered by the Division of Environmental Management, is
required before construction, operation, or substantial modification of any
structure used for transferring, transporting, storing, processing or refining
oil, including pipelines. The applicant must submit to DEM the nam and
address of the owner and operator, the principal officers' names, the number
of employees, maps, plans, specifications, accident mitigation measures, and
an assessment of impacts on fish, wildlife, air, water, and public lands.
After completion of the application, circulation to interested agencies, and a
public notice, hearing, and comment period, a permit decision will be made.
The processing is usually completed in about 160 days. The approved permit,
however, is not considered effective until necessary water and air quality
permits have been obtained. In addition, the applicable laws require annual
reports of facility activity every February 1.

4. Coast Guard Port Adequacy Certificate
33 U.S.C. �1901 et seq.

Pursuant to the MARPOL Protocol of 1978, relating to the 1933 Inter-
national Convention for the Prevention of Pollution from Ships, a port or
terminal facility needs Coast Guard approval as to its adequacy for the
transfer of oil or noxious liquid.

E. Phase IV: Production

It Is at this point, when offshore drilling structures, onshore terminal
facilities, and their linking transportation systems, whether pipelines or
tankers, are ready for operation, that oil and gas are brought ashore and
processed. Again, this phase may overlap with the exploration and development

E-19

stages. The amount of activity at the production stage will vary with the
demand for petroleum products in the area. If it is a very high demand area,
,the oil companies will settle many of their refining and production operations
there; otherwise these operations are likely to be located elsewhere. These
operations tend to locate where there is a big market for their products, even
if this is relatively distant from the source of oil, since it is more expen7
sive to transport finished petrochemical products in all their forms than to
transport the unrefined oil.

Again, some of the same permits may be required for production activities
as for exploration or development (see Phases II and III above, and Table
3-2). In addition, the following certifications and permits may be required:

1. Public Water Supply Certification (possible)
N.C. Gen. Stat. �130-13D; 10 NCAC IOD

This certification may be required at the production stage if production
reaches a level of activity requiring expansion of the existing public water
supply system or construction of a new one. To be certified, a sanitary
survey is required for proposed surface or groundwater sources or well sites.
In addition, plans, specifications, and engineering reports must be submitted
to the Environmental Health Section of the Department of Human Resources.

2. Oil Refining Facilities Permit (possible)
N.C. Gen. Stat. �143-215.100-.102; 15 NCAC IF .0001-.0013

A permit is required from the Division of Environmental Management to
construct and operate an oil refining facility in North Carolina.

3. Coast Guard Permits and Certifications
33 CFR 126.27; 46 CFR 1,54; 49 CFR 176.27

A general permit is required for the handling of dangerous cargo (includ-
ing liquified petroleum gas and crude oil) at port, if tankers rather than
pipelines are used. A certificate of inspection is required for self-
propelled vessels carrying bulk liquified gas as well as one for containerized
(non--bulk) shipment.

F. Additional Considerations

Many of the permits require circulation to, comments from, and/or con-
sultation with other agencies before a permit is granted. This review process
is conducted internally in the government and thus requires no additional
action on the applicant's part, unless specified. A few of the non-permitting
agencies most often consulted are described below.

The Wildlife Resources Commission NRC) must be consulted if any of the
17 listed endangered or four threatened species of wildlife will be affected
by the development. All actions requiring government permits are required to
address the impacts on these species prior to issuing a permit. Projects may

E-20

be modified, upon WRC recommendation, to preclude any adverse impact on the
species or its habitat.

The U.S. Fish and Wildlife Service must be consulted before the permit-
ting of exploratory wells (15 NCAC .0004) and the issuance of federal permits.

The North Carolina Historic Preservation office, within the Department of
Cultural Resources, is arged with reviewing all CAMA Permits and all state
and federal land disturbing permits. If a property is determined to be
historically or archaeologically significant, the effect of the project on the
property is assessed, and alternative possibilities, if thought necessary, are
suggested.

Under 16 U.S.C. �470f and 30 CFR 60 and 63, the federal Advisory Council
on Historic Preservation must be provided a reasonable opportunity to
comment on any federal action affecting any "district, site, building, struc-
ture, or object that is included or eligible for inclusion in the National
Register" of Historic Places. Any federal department or agency, before
issuing a license or permit, must consider the effect of the proposed under-
taking on these places. The criteria for eligibility (36 CFR 60.4) broadly
include any thing or place that may yield important information on prehistory
or history.

Finally, under the federal Coastal Zone Management Act and North Carolina
Executive Order #15, consistency certification is required from the state
before any federal permitting or state action, to assure that the proposed
action is consistent with the state's coastal program.

One last consideration is the effect of local legislation, regulation, or
zoning in the area of activity. Pursuant to state law, local governments may
adopt land use plans which could affect oil and gas production; in coastal
areas, CAMA requires that local plans classify all land as "developed,"
"transition," "community," or "conservation," and that any CAMA development
permits be consistent with these plans. In addition, the General Assembly has
recently passed legislation authorizing counties to regulate development in
estuarine waters and public trust lands under navigable waters; this act may
significantly increase the role of local government in regulating oil and gas
activities (see Chapter 5). Under state law, local governments may also
require environmental impact assessments (N.C. Gen. Stat. �113A-8) enact
stricter erosion control ordinances than the State's (�113A-54), and enact
ordinances and regulations regarding oil pollution control (�143-215.82). All
of these possibilities should be considered prior to activity in the area.

E-21

APPENDIX F

Lease Form for Oil and Gas Mining in Submerged Lands

Introduction

The following "model lease" is an attempt to expose the reader to the

necessary provisions of an oil and gas lease and to various options for draft-

ing these provisions. In some sections, the clauses currently used in North

Carolina leases are compared to those of other states. In others, a single

clause, felt to be the best example, is presented and discussed.

In deciding which form of lease to adopt, several factors come into play.

First, the bargaining power of the parties should be considered in light of

the prospects for discovery of oil or gas. In states such as Texas, with

proven reservoirs of offshore oil, the state is in a superior bargaining

position compared to states like North Carolina, where the existence of

reserves is speculative. A second and related consideration is the fairness

of the provisions to the parties; the state should arguably take the upper

hand, but not to such an extent as to completely dominate the lessee's activi-

ties. Finally, the controlling consideration should be the best interest of

all the citizens of the state; the lease should therefore reflect a balance

between the energy, environmental, commercial, and recreational concerns of

the people of North Carolina.

F-1

North Carolina Oil and Gas Lease

This AGREEMENT, made and entered into this day of
19 , by and between the STATE OF NORTH CAROLINA, acting by and through the
North Carolina Department of Administration and the North Carolina Department
of Natural Resources and Community Development, the State hereinafter desig-
nated as the "Lessor," and

hereinafter designated as the "Lessee."

WITNESSETH

THAT WHEREAS, the North Carolina Department of Administration has recom-
mended to the Governor and Council of State the leasing of certain mineral
interests in the properties hereinafter described; and

WHEREAS, the North Carolina Department of Natural Resources and Community
Development, hereinafter referred to as "Department," has recommended and
approved the leasing of certain mineral interests in the properties herein-
after described; and

WHEREAS, the Governor and Council of State of North Carolina at a meeting
held in the City of Raleigh, North Carolina, on the day of 9
19 , approved this lease agreement and directed the execution thereof; and

WHEREAS, the Lessee desires an exclusive lease covering certain mineral
deposits within the area hereinafter described, to wit: Oil, and gas; and

WHEREAS, the party of the first part is fully authorized and empowered to
enter into and execute this lease agreement pursuant to GS 146-8 of the North
Carolina General Statutes.

NOW, THEREFORE, for and in consideration of to it in
hand paid, the receipt of which is hereby acknowledged, together with the
covenants and agreements of Lessee hereinafter set forth, which are to be
paid, kept and performed by Lessee and which are made conditions precedent
to the continuance of this lease, Lessor has leased and by these presents
does lease unto Lessee in the below described area the exclusive right and
privilege to drill for, mine, extract, remove and dispose of oil and gas in
or under the following described area of the submerged lands of the State of
North Carolina to which the State is authorized to make leases by authority of
GS 146-8 of the North Carolina General Statutes; to wit: [description]

Said land, hereinafter referred to as the leased area, is estimated to
comprise acres, whether it comprises more or less.

[Comments]

The amount of consideration has been left blank, although North Carolina

has in the past asked for a nominal one dollar. The current prevailing

F-2

practice is to include a "bonus" payment as consideration for the execution of

the lease. This amount varies widely depending on the prospects for and

success in the particular area. It should be more than a nominal amount to

avoid any legal challenge-as to whether the lessee is a "bona fide purchaser

for value" who has acquired a definite property interest.

The above Preamble corresponds with the leasing procedures historically

practiced in North Carolina. If this procedure is changed, the Preamble may

require alteration and clarification of the process used for granting the

lease. Thus, the parties' signatures on the lease will indicate that the

correct procedures were followed, avoiding potential challenges on this issue.

If a competitive bidding process is adopted, the following wording, based on

Texas and Louisiana leases, may be used:

WHEREAS, pursuant to North Carolina General Statutes and
subject to all rules and regulations promulgated by the North Carolina
Department of Administration and Department of Natural Resources and Community
.Development (hereinafter, "Department") pursuant thereto, and all other
applicable statutes and amendments to said General Statutes, the State of
North Carolina, hereinafter referred to as "Lessor," advertised for bids for
a lease covering oil, gas, and other liquid or gaseous minerals in solution
and produced with oil or gas on the property described below; and

WHEREAS, in response to required advertisements, bids were received and
duly opened and considered in the City of Raleigh, Wake County, State of North
Carolina, on the_ day of , 19 , at a meeting of
the [controlling board, commission, or agency] of
the State of North Carolina; and

WHEREAS, the [controlling board] accepted the bid
of
whose mailing address is
hereinafter referred to as "Lessee,"
as being the best and highest [or, "most advantageous"] to the State of North
Carolina.

NOW THEREFORE, [same as above]

F-3

Section 1: Rights of Lessee. In addition to the exclusive rights and
privileges set out above, Lessee has:

(a) the nonexclusive right to conduct within the leased area geological
and geophysical explorations in accordance with applicable
regulations;

[Comment)

This subsection may be included, alternatively or additionally, under

Section 2: Reservations to Lessor, as a right which may be granted to other

parties by the State.

(b) the nonexclusive right to drill water wells within the leased area,
unless the water is part of geopressured-geothermal and associated
resources, and to use water produced therefrom for operations free
of cost, provided that such drilling is conducted in accordance with
procedures approved by the Department; and

(c) in the event it becomes necessary for the full enjoyment of the
rights granted by this lease, Lessee may apply to Lessor for ease-
ments and permits to construct or erect and to maintain within the
leased area all platforms, fixed or floating structures, sea walls,
docks, dredged channels and spaces, buildings, plants, telegraph or
telephone lines and cables, pipelines, reservoirs, tanks, pumping
stations and other works and structures. Approval of such easements
and permits shall not be unreasonably withheld.

Section 2: Reservations to Lessor. All rights in the leased area not
expressly granted to Lessee by this lease are hereby reserved to Lessor.
Without limiting the generality of the foregoing, such reserved rights
include:

(a) Geological and geophysical exploration; rights-of-way. The right to
authorize the conduct of geological and geophysical exploration in
the leased area which does not interfere with or endanger actual
operations under this lease, and the right to grant such easements
.or rights-of-way upon, through, or in the leased area as may be
necessary or appropriate to the working of other lands or to the
treatment and shipment of products thereof by or under authority of
the State of North Carolina, its Lessees or Permittees.

(b) Leases on other minerals. The right to grant leases for the extrac-
tion of any minerals or products other than oil and gas within the
leased area or any part thereof. No lease of other minerals or
products shall authorize or permit the Lessee thereunder unreason-
ably to interfere with or endanger operations under this lease.

F-4

Section 3: Term. This lease shall continue for a period of
years, hereinafter the "primary term," from the effective date of this lease
and so long thereafter as oil or gas may be produced in paying quantities from
the leased area or areas pooled therewith, or so long as this lease is held in
force by drilling or well reworking operations or as otherwise provided for
hereinafter, and as approved by the Department.

[Comments]

Most states have a primary term'of three to five years, though California

has a twenty year term. The shorter the primary term, the sooner the Lessee

will be encouraged to commence operations; however, an area in which little

exploration has been conducted may need a longer term so that preliminary

surveying can be done.

Production in "paying quantities" may need some further definition.

Therefore, a "Definitions" section should be included in the lease to clarify

this and other possibly ambiguous terms.

Section 4: Rental.

Option 1: Lessee agrees to pay Lessor on or before the first day of
each primary term year commencing prior to a discovery of oil or gas on the
leased area, a rental of per acre or fraction thereof. Provided,
however, if Lessee drills, participates in the drilling of, or causes to be
drilled, one or more exploration wells that reach basement rock, as determined
by the Department, in each area described herein, the annual rent paid for the
year in which the exploration well, or wells, was drilled will be returned to
Lessee. Provided further, in the event Lessee's lease area consists of more
than one lease block, as herein described, it is understood and agreed that
the drilling of one exploratory,well to basement rock will serve to fulfill
all drilling requirements herein stated, and will qualify the Lessee to
receive a return payment of all rents paid on up to ten (10) individual lease
blocks for the year in which the exploratory well, or wells, was drilled.
This repayment of rents provision applies only to the first and second year of
the original primary term.

[Comment]

This.option, the current North Carolina provision, is an example of a

"drill or pay" lease, making payment of delay rentals an obligation of the

lessee, and allowing the lessor to either take legal action for breach of

contract or terminate the lease if the lessee does not pay its rental payment

F-5

for the given year. This option requires payment of rental after the second

year, even if drilling occurs, giving the lessee initiative to start opera-

tions and avoid payments early in the lease, but not to continue them. This

may lead to rushed operations which may not be as productive as better planned

ones. The power that this provision gives the lessor is somewhat diminished

by the clause usually included in the lease giving lessee the right to

surrender all or any portion of its lease at any time. The "drill or pay"

form of rental is no longer widely used.

Option 2: The Lessee shall pay to the State annually in advance,
rental of dollars ($ ) per year for the first three years
of the lease.. Thereafter, rental shall be one dollar ($I) per acre per year
and shall be payable annually in advance. If any portion of the leased lands
is quitclaimed as to all zones, the annual rental shall be reduced one dollar
($1) for each acre quitclaimed with the reduction effective on the lease
anniversary date next following the date of quitclaim. However, under no
circumstances, including quitclaim of all or any part of the leased lands,
shall there by any reduction in the rental obligation for the first three
years.

[Comment]

This provision is used in California, where the rental is ten million

dollars per year for the first three years of a twenty year lease. The amount

of payment should depend on the prospective value of the particular tract.

This provision guarantees the state substantial payments because the first

three years are a fixed payment, regardless of operations on the lands or

surrender of all or part of the lands. Because of this fixed payment,

however, there is little incentive for the lessee to begin operations

during this period.

Option 3: If actual drilling operations are not commenced on the
leased area in good faith on or before one year from the date hereof, this
lease shall terminate as to both parties unless Lessee on or before the
expiration of said period shall pay or tender to Lessor the sum of
dollars ($
(hereinafter called "rental"), which shall extend for one year the time within
which actual drilling operations may be commenced. Thereafter, annually, in

F-6

like manner and upon like payments or tenders, the commencement of actual
drilling operations may be further deferred for successive periods of twelve
(12) months each during the primary term. Payment or tender of rental may be
made by check or draft of Lessee made payable to the order of The State of
North Carolina and mailed or delivered to the North Carolina State Treasurer,
on or before the rental payment date.

[Comment]

This provision, known as an,"unless" clause, is the one most commonly

used. It gives the lessee some incentive to begin operations early, to avoid

payments and make money for itself as well. This option favors the lessee

more than the lessor, since the only result of failure to drill or pay is

termination of the lease, and there can be no action for breach of contract as

in Option 1. While the term "actual drilling operations" may be vague, it can

be better defined in this clause or in a separate lease section of defini-

tions. While Alabama combines its rental provision with the Extension of Term

section in its standard lease, other states do not; this combination is

probably not advisable. This clause may be altered, as in Texas, to require

payment on a "per acre" basis.

Option 4: Rentals.

(a) Lessee shall pay annual rental to the State in accordance with
the following rental schedule:

(1) for the first year, $1.00 per acre or fraction of an acre;
(2) for the second year, $1.50 per acre or fraction of an acre;
(3) for the third year, $2.00 per acre or fraction of an acre;
(4) for the fourth year, $2.50 per acre or fraction of an acre;
(5) for the fifth year and following years, $3.00 per acre or
fraction of an acre; provided that the State may increase the
annual rental rate as provided by law upon extension of this
lease beyond the primary term.

(b) Annual rental paid in advance is a credit on the royalty or net
profit share due under this lease for that year.

(c) Lessee shall pay the annual rental to the State of North Carolina
(or any depository designated by the State with at least 60 days' notice to
Lessee) in advance, on or before the.annual anniversary date of this lease.
The State is not required to give notice that rentals are due by billing
Lessee. If the State's (or depository's) office is not open for business on

F-7

the annual anniversary date of this lease, the time for payment is extended to
include the next day on which that office is open for business. If the annual
rental is not paid timely, this lease automatically terminates as to both
parties at 11:59 p.m., Eastern Standard Time, on the date by which the rental
payment was.to have been made.

[Comment]

This provision from Alaska's standard lease is probably the best alterna-

tive from the state's perspective. It guarantees the state some revenue,

unlike options 1 and 3, but it also provides a strong incentive for the lessee

to begin operations as soon as possible, since each year of delay will cost

significantly more than the preceding year. Rental per acre and increments of

increase can be varied; Florida, for example, does not begin raising the

rental price until after two years. Likewise, the provision for automatic

termination may be amended to comply with the state's policy.

Section 5: Royalties on Production.

A. Royalty Payments.

Option 1: In the event oil or gas is produced by Lessee in paying
quantities from the leased premises, Lessee will develop and operate such oil
or gas field so as to continually produce and save oil or gas therefrom, all
in a reasonable and prudent manner according to sound economic principles and
practices and will make payments as follows:

1. For all oil produced and saved from the leased premises, Lessee will
pay to Lessor one-sixth (1/6) of the market price at the well for
oil of like grade and gravity prevailing on the day such oil is run
into the pipelines or into field storage tanks.

2. For the gas from each well, where only gas is found, Lessee will pay
to Lessor one-sixth (1/6) of the market price at the well for gas
produced from any well and used by Lessee off the premises. For gas
produced from any oil well and used off the premises or for the
manufacture of casinghead gasoline, Lessee will pay to the Lessor
one-sixth (1/6) of the market price at the well for the gas so used.

[Comment]

This option, the current North Carolina provision, has the benefit of

simplicity and straightforwardness; however, this simplicity may lead to

F-8

unnecessary confusion in interpretation. Exactly which types and uses of oil

and gas command royalties and how market price is determined need clarifica-

tion. Since all oil and gas production is to be charged the same percentage

royalty payment, the separate provisions.for oil and gas might be consolidated

to say "operations under this lease," with some elaboration of how market

price is determined.

Option 2: When production of oil and/or gas is secured, Lessee
agrees to pay or cause to be paid to Lessor, as follows:

1. Oil: As a royalty on oil, which is defined as including all hydro-
carbons produced in a liquid form at the mouth of the well and also all
condensate, distillate, and other liquid hydrocarbons recovered from oil or
gas run through a separator or other equipment, as hereinafter provided,
part of the gross production or the market value thereof, at the option
of the Lessor, such value to be determined by (1) the highest posted price,
plus premium, if any, offered or paid for oil, condensate, distillate, or
other liquid hydrocarbons, respectively, of a like type and gravity in the
general area where produced and when run, or (2) the highest market price
thereof offered or paid in the general area where produced and when run, or
(3) the gross proceeds of the sale thereof, whichever is the greater. If no
other oil is produced in the general area, value shall be determined by the
highest gross price paid or offered the producer. Lessee agrees that before
any gas produced from the land hereby leased is sold, used or processed in a
plant, it will be run free of cost to Lessor through an adequate oil and gas
separator of conventional type, or other equipment at least as efficient, to
the end that all liquid hydrocarbons recoverable from the gas by such means
will be recovered. Upon written consent of Lessor, the requirement that such
gas be run through such a separator or other equipment may be waived upon such
terms and conditions as prescribed by Lessor.

2. Non-Processed Gas: As a royalty on any gas (including flared gas),
which is defined as all hydrocarbons and gaseous substances not defined as oil
in subsection (1) above, produced from any well on said land (except as pro-
vided herein with respect to gas processed in a plant for the extraction of
.gasoline, liquid hydrocarbons or other products) _ part of the gross
production or the market value thereof, at the option of Lessor, such value to
be based on the highest market price paid or offered for gas of comparable
quality in the general area where produced and when run, or the gross price
paid or offered to the producer, whichever is the greater.

3. Processed Gas: As a royalty on any gas processed in a gasoline plant
or other plant for the recovery of gasoline or other liquid hydrocarbons,
part of the residue gas and the liquid hydrocarbons extracted or the
market value thereof, at the option of Lessor. All royalties due herein shall

F-9

be based on one hundred percent (100%) of the total plant production of
residue gas attributable to gas produced from this lease, and on fifty percent
(50%) or that percent accruing to Lessee, whichever is the greater, of the
total plant production of liquid hydrocarbons, attributable to the gas
produced from this lease; provided that if liquid hydrocarbons are recovered
from gas processed in a plant in which Lessee (or its parent, subsidiary or
affiliate) owns an interest, then the percentage applicable to liquid hydro-
carbons shall be fifty percent (50%) or the highest percent accruing to a
third party processing gas through such plant under a processing agreement
negotiated at arms' length (or if there is no such third party, the highest
percent then being specified in processing agreements or contracts in the
industry), whichever is the greater. The respective royalties on residue gas
and on liquid hydrocarbons shall be determined by (a) the highest market price
paid or offered for any gas (or liquid hydrocarbons of comparable quality) in
the general area or (b) the gross price paid or offered for,such residue gas
(or the weighted average gross selling price for the respective grades of.
liquid hydrocarbons), whichever is the greater. In no event, however, shall
the royalties payable under this paragraph be less than the royalties which
would have been due had the gas not been processed.

4. Other Products: As a royalty on carbon black, sulphur or any other
products produced or manufactured from gas (excepting liquid hydrocarbons)
whether said gas be "casinghead," "dry" or any othe 'r gas, by fractionating,
burning or any other processing, - part of the gross production of such
products, or the market value thereof, at the option of Lessor, such market
value to be determined as follows:

a. on the basis of the highest market price of each product, during
the same month in which such product is produced, or

b. on the basis of the average gros s sale price for each of the
products for the same month in which such products are produced;
whichever is the greater.

5. No Deductions: Lessee agrees that all royalties accruing to Lessor
under this lease shall be without deduction for the cost of producing, gather-
ing, storing, separating, treating, dehydrating, compressing, processing,
transporting, and otherwise making the oil, gas and other products produced
hereunder ready for sale or use.

[Comment]

This subsection, excerpted from the Texas Standard Lease, gives more

detailed definitions of oil and gas. It also assures the lessor the benefit

of the highest possible calculation of the market value. While this method

may be the most beneficial to the state, it requires a lot of record keeping

and calculation on the part of the lessee. Some of the provisions,

F-10

particularly that the product be delivered to the state at the lesseels

expense and that there be no deductions for production costs, are standard

with proven reservoirs of oil and gas. In North Carolina's situation, it may

be advisable to lower the royalty share in consideration of these expenses, or

to adopt a net profit share-form of payment (see Section 6: Share of Net

Profit). The alternatives for payment in kind or in value can be included in

these provisions, as done here or as a separate provision.

Option 3: Royalty shall be as follows:

(a) On oil (which includes condensate and other liquid hydrocarbons):
20% of the market value at the well as hereinafter defined of all oil produced
and marketed hereunder and not used for fuel in conducting operations on the
land leased hereunder or pooled herewith or in treating to make marketable the
products therefrom. Market value for oil is hereby defined as the current
posted price for oil of like grade and quality currently prevailing in that
field on the date it is run into the pipeline, barge, or other conveyance used
in transporting oil from the well, without any deductions whatsoever except
applicable severance taxes paid on production and processing costs, as defined
in subsection (c) hereinafter. In the event no posted price exists in the
field, then the average of the posted price of oil of like grade and quality
currently prevailing in the three nearest offshore fields of similar size
shall be used to compute market value in accordance herewith.

(b) On gas (including casinghead gas or other gaseous substances
produced and saved from said land):

(1) On gas in its natural state or otherwise, not sold but rather
utilized off the premises by Lessee for purposes other than the recovery,
extraction or manufacture of gasoline or other products therefrom, 20% of the
market value of the gas at the well.

(2) On gas marketed in its natural state or otherwise, 20% of the
net proceeds received by Lessee from such sale; and if processed by an I .
unaffiliated third party on behalf of Lessee for the recovery, extraction or
manufacture of gasoline, sulphur or other products therefrom in any plant, 20%
of the proceeds received by Lessee (i) under the agreement of contract gov-
erning such processing on behalf of Lessee, or (ii) from the sale by Lessee of
the products delivered or allocated to Lessee thereunder, subject to Lessor's
rights to review any gas contract as hereinafter provided in (b)(5) below.

(3) On gas processed by Lessee itself or any of Lessee's wholly or
partially owned affiliates or subsidiaries for the recovery, manufacture or
extraction of gas, gasoline, sulphur or other products therefrom in any plant:
W 20% of the net proceeds derived from the sale of such gas, gasoline,
sulphur or other product so recovered, extracted or manufactured, or (ii) at

F-11

Lessor's election 20% of the gasoline, sulphur or other products in kind, so
recovered, extracted or manufacture'd, and 20% of the net proceeds at the out-
let side of such plant of any residue gas, subject to sales contract review by
Lessor as hereinafter set forth in (b)(5) below. In the event of Lessor's
election to take in kind its 20% share of the gasoline, sulphur or other pro-
ducts so recovered or manufactured, Lessor shall be charged its proportionate
share of the direct cost and expenses of recovering, extracting and manufac-
turing such gas, gasoline, sulphur or other products. Nothing herein shall be
construed as obligating Lessee to recover, extract or manufacture gasoline,
sulphur or other products in any plant.

(4) "Net proceeds" as used herein shall be defined as the proceeds
remaining after deducting from the sales price received under any bonafide
contract for sale of gas, gasoline, sulphur or other products applicable
severance tax and processing costs, as defined in subsection (c) hereinafter.

(5) Upon entering any gas sales contract, Lessee shall submit said
contract to Lessor who shall have six months to elect to ratify said contract
and be governed by its provisions or to reject said contract, market or pro-
cess its own gas, and by so doing release Lessee from its obligations to
market hereunder. Failure to take any action shall constitute ratification of
the contract. By ratifying the contract, Lessor agrees to accept all clauses
in the contract including the pricing provisions thereof.

(6) Nothing contained in this lease shall be interpreted as limit-
ing the right of Lessor to take its gas royalty in kind; provided, however,
the election to take gas royalty in kind is a one time election which the
Lessor must elect within the above described six-month period (see (b)(5)
above) or forever waive its right to take in kind the gas which is the subject
of such contract so ratified by Lessor. Failure to make an election shall
constitute an election not to take in kind.

(c) In all cases under paragraphs (a) and (b) hereinabove wherein Lessee
is allowed to deduct certain specified costs from the amounts due Lessor as
royalty, such deductions are hereby termed to be "processing costs." Process-
ing costs shall mean all of the cost and expense incurred in connection with
transporting, compressing, and treating to make marketable the minerals
covered by this lease from the time they are produced at the wellhead until
the products extracted therefrom are ready for sale at the tailgate of any
treating facility. Such processing costs shall be limited to the following
items: (1) cost 'incurred in transporting the mineral from the wellhead to
any treating facility; (2) direct operating cost for stabilization, sulphur
recovery, compression and gas treating, and overhead directly related to the
processing of the minerals taken from the leased premises; and (3) deprecia-
tion on the facilities used for transporting the minerals, stabilization,
sulphur recovery, compression and gas treating, at a rate not to exceed ten
percent (10%) per annum based upon the useful life of the facility and the
gross investment therein of the Lessee, subject to the limitations set forth
hereinafter.

In no event shall processing costs, including depreciation costs, include
any profit on processing operations or return on capital investment. All of

F-12

the processing costs specified in subparagraphs (1), (2) and (3) above will be
on an actual year's experience basis. At the end of each year, the costs will
be tabulated, and if there is any overpayment by Lessor, the same will be
repaid by Lessee within sixty (60) days; if there is any underpayment by
.Lessor, the same will be deducted from future royalty. Any fuel from the
well stream used in processing attributable to the Lessor's royalty interest
share of the minerals, will be provided free of charge from royalty
obligation.

All depreciation and processing costs will be calculated on a prorata
basis for the total production of the plant and will be allocated back to the
share of production attributable to Lessor's royalty and shall be limited to
that percent of the total plant production attributable to production under
this lease.

Lessee shall provide, on a monthly basis, a recapitulation depicting all
costs, including processing and depreciation costs, deducted from Lessor's
royalty.

Nothing expressed or implied by this lease shall obligate Lessee to
transport or process minerals produced under this lease.

[Comment]

This option, from the Mississippi lease, combines methods for calculating

royalties by using a strict "market value" basis for oil and for gas used

by lessee, and a "net proceeds" basis for gas sold by lessee. This option

thus allows recovery of royalties based on the sale price for substances sold

and based on the prevailing price for substances used or stored for later

sale, giving the state its proportion of the value at the time of extraction.

Further, it allows deductions from these amounts for severance taxes and costs

of production. This detailed option is arguably the fairest, though it may be

more lengthy than desired.

Option 4: In the event oil or gas is produced by Lessee in paying
quantities from F-he leased premises, Lessee will develop and operate such oil
or gas field so as to continually produce and save oil or gas therefrom, all
in a reasonable and prudent manner according to sound economic principles and
practices and will make payments as follows:

1. For all oil produced and saved [or sold] from the leased premises,
Lessee will pay or cause to be paid to the Lessor part of
the market value at the well for such oil. Oil is defined as including all
hydrocarbons produced in a liquid form at the mouth of a well and also all
condensate, distillate, and other liquid hydrocarbons recovered from oil or

F-13

gas run through a separator or other equipment and shall include, for royalty
purposes, that oil used for fuel in conducting operations on the land leased
hereunder or pooled herewith or in treating to make marketable the products
therefrom. Market value is defined as the current posted price for oil of
like grade and quality prevailing in that field on the day it is run into the
pipeline, barge, field storage tank, or other conveyance used in transporting
or storing oil from the well. In the event no posted price exists in the
field, the average of the posted price of oil of like grade and quality
currently prevailing in the three nearest offshore fields of similar size
shall be used to compute market value. [If neither of these two methods is
practicable, market value at the well can be determined by the net proceeds
received by Lessee from the sale of such oil.]

2. For the gas from each well, where only gas is found, Lessee will pay
or cause to be paid to Lessor part of the market
value at the well for gas produced from any well and used by Lessee [or other
parties] off the premises, the market value of gas being calculated in the
same way as described for oil in subsection one (1) above. Gas is defined as
all hydrocarbons and gaseous substances which are not defined as oil in sub-
section one (1) above.

. 3. For gas produced from any oil well and used off premises by Lessee
[or other parties], or used for the manufacture of casinghead gasoline, Lessee
will pay or cause to be paid to Lessor part of the market
value at the well for thegas so used, the market value being calculated
in the same way as described for oil in subsection one (1) above.
[Comment]

Making these minor modifications to the current North Carolina provision

may be the best option. Better definitions of oil, gas, and "market value at

the well," as included here, should make the clause adequate. The survey of

other states' lease forms indicated varying categorization of the gas dis-

covered, according to type of well, processing procedures, or type of user.

This provision has been drafted to reflect the current North Carolina lease

distinctions; using different classifications, or no classifications at all

(as in option 3), should be considered before adopting a royalty clause.

Certain portions of this option have been bracketed to indicate that they

are optional. The provision regarding net proceeds provides a last choice

alternative for calculating market value, though it may raise more problems,

in deciding when to use this method, or what "net proceeds" covers, than it

F-14

settles. If this clause is adopted, a clause regarding deduction of the costs-

of production should be considered (see Options 2 and 4). The "or other

parties" and "or sold" sections have been bracketed because it is unclear

whether or not the intent of the existing royalty clause is to charge royal-

ties on oil and gas sold to or used by parties other than the lessee. It is

usually the case that royalties are not charged for oil and gas used on the

premises for drilling operations and that they are charged for products sold.

Although this intent is implied by references to royalties only on oil "saved"

or gas used off premises, it might be advisable to include an explicit state-

ment to this effect in this section or elsewhere.

B. Payment in Kind

Option 1: In lieu of monetary payments as provided for in Sub-
section A above, Lessor may at any time, and from time to time, with sixty
(60) days written notice to Lessee elect to receive in kind its royalty share
of oil and/or gas for the subsequent payment period as described in Subsection
D below. Such royalty share shall be delivered to Lessor or the Lessor's
credit into field storage tanks or pipelines as designated by Lessor, at
Lessor's sole cost and expense. Title to such royalty share shall pass at the
point of delivery to Lessor. Lessor's royalty share shall be computed as the
same proportionate share(s) of oil and/or gas agreed upon in Subsection A
above, as produced and delivered into Lessee's field storage tanks or
pipelines during the same period.

[Comment]

An "in kind" clause is a standard part of an oil and gas lease. This one

is drawn from the existing North Carolina lease, with a few alterations. The

notice period has been changed from thirty to sixty days to conform to the

provisions of most other states. The period for which payment may be made in

kind has been clarified to extend for a full one-month period, as opposed to

the existing clause which could conceivably allow confusing fluctuation

between monetary and in kind payment on a daily basis. The payment period

(see Subsection D below) has been changed from two months to one month, so

F-15

that in kind payments will last for a one-month minimum and the option may be

re-exercised each month. Some states, including Florida and Mississippi,

allow exercise of this option only once a year for a full year period.

Option 2: Lessor shall have the option to take in kind its royalty
on oil at any time upon Lessor giving Lessee 90 days written notice to that
effect. The acceptance by Lessor of a royalty other than in kind shall not be
construed as a waiver of Lessor's option to take its oil royalty in kind at
later dates or times. Upon 90 days written notice to Lessee, Lessor may
revoke such election so as to again require Lessee to handle and dispose of
Lessor's share of all oil royalty. Provided, however, no option by Lessor
hereunder shall be exercised at time intervals of less than one year, so that
once an election is made and executed, the option hereunder cannot be again
exercised for a period of at least one year. Lessor's portion of oil produced
when Lessor elects to take in kind shall be delivered to Lessor at Lessor's
option either (1) into Lessor's field storage facilities, or (2) to Lessor's
credit into any pipeline or other facility into which the oil is delivered to
a purchaser.

[Comment]

This alternative payment-in-kind clause requires no notice to continue

in--kind payments once the option has been invoked. Rather, it requires the

lessor to notify the lessee to return to payment of monetary royalties. This

clause also permits the lessor only to invoke the in-kind option once per

year, for a full year period, thereby saving the parties from the confusion of

switching payment form too often.

There are other alternative clauses for the "in kind" section. One might

be to cause the lessee to incur some of the expenses of delivery or storage,

particularly those corresponding to any nondeductible expenses which would

occur if payment by lessor was received in value rather than in kind. Another

way of drafting this provision would be to include it in the same subsection

that describes royalty payments (see Subsection A, above).

F-16

C. Standard Measurement of Gas and Oil

The standard units of measurement in determining payments under
subsections A and B above are the stock tank barrel and the standard unit of
gas as defined by the American Petroleum Institute as follows:

1. The stock tank barrel shall equal 42 U.S. gallons at 14.65 psi and 60
degrees Farenheit;

2. The standard unit of gas shall be the cubic foot measured at 14.65
psi and 60 degrees Farenheit.

All meters and measuring devices used in handling produced oil
and/or gas under the terms of this lease shall be calibrated to the standards
set forth in this paragraph.

[Comment]

This important subsection may alternatively be included in the

definitions of oil and gas in Subsection A above. However, listing these

standards within Subsection A might only serve to make it more confusing.

D. Payment of Royalties

All royalties not taken in kind shall be made by check or draft of
Lessee, drawn to the order of the State of North Carolina and mailed or
delivered to the office of the North Carolina State Treasurer in Raleigh,
North Carolina, on or before the 15th day of the second month next following
the month of production. Each payment shall be accompanied by the affidavit
of Lessee, or Lessee's authorized agent, showing (1) the gross amount of pro-
duction, (2) disposition, and (3) the gross sales value or proceeds received,
of all oil, gas or other liquid or gaseous hydrocarbon mineral, and their
respective constituent products, produced from the leased area or acreage
pooled therewith. Lessee shall retain for not less than two (2) years a copy
of all documents, records or reports confirming the gross production, dispo-
sition and gross sales values or proceeds received, including gas meter read-
ings (corrected to standard temperature and pressure), pipeline receipts, gas
line receipts, and other checks or memoranda of amount produced and put into
pipelines, tanks or pools and gas lines or gas storage, all gas contracts
(whether for sale or process) and amendments thereof, and any other reports or
records which the State Lands Division may require to verify said gross pro-
duction, disposition and gross sales values or proceeds received; and all such
records shall at all times be subject to inspection and examination by the
Secretary of the Department of Natural Resources and Community Development of
North Carolina or his duly authorized representative. Lessee shall bear
all responsibility for paying or causing all royalties to be paid as
prescribed by the due date provided herein.

F-17

[Comment]

This provision, taken from the Alabama standard lease, is more complete

than the existing North Carolina provision. This conforms with the prevailing

practice of requiring monthly payment of royalties and submission.of

supporting documents, as opposed to the existing North Carolina bimonthly

requirement.

E. Minimum Royalty

Option 1:

At the expiration of each lease year commencing after discovery of
oil or gas, or after the expiration of the primary term of this lease, if this
lease is maintained by production, the royalties paid to Lessor in no event
shall be less than an amount equal to the total annual delay rental herein
provided for in Section 4; otherwise, there shall be due and payable on or
before the last day of the month succeeding the anniversary date of this lease
a sum equal to the total annual rental less the amount of royalties paid
during the preceding year.

[Comment]

A minimum royalty provision is important as both an incentive for the

lessee to continue productive and profitable operations and as a guarantee of

payment to the lessor. This option, based on the Texas provision, states the

requirement for minimum royalties in a simpler manner than the existing North

Carolna clause. While this clause provides for minimum royalties equal to

delay rentals, other states provide for larger minimum royalties, sometimes

twice the delay rental. The amount charged depends on the size of the pre-

scribed delay rentals, the prospects for profitable production, and the

overall bargaining power of the state. In the case of North Carolina, with

undetermined reservoirs of oil and gas, both delay rentals and minimum royal-

ties should remain relatively low.

F-18

Option 2:

The minimum amounts payable under this lease for each lease year
shall be, in any event, not less than $ per lease year, if during
the primary term, and not less than $ per lease year, if after the
expiration of the primary term of this lease, @ibich amount shall be called
.. minimum royalty". If for any such lease year the accrued royalty plus any
delay rentals (where the lease is still in the primary term) or shut-in well
royalties that have been paid for such lease year equals or exceeds the
minimum royalty, then the terms of this paragraph shall not apply. If, how--
ever, for any such.lease year the accrued royalty, together with any amounts
paid as delay rentals or shut-in well royalties is less than the minimum
royalty, then Lessee shall within sixty (60) days following the close of such
lease year, pay or tender to Lesso Ir, as prescribed in Section 5D above, the
difference between the minimum royalty and an amount equal to 'the accrued
royalty plus any delay rentals and shut-in well royalties paid for such year.

[Comment)

This option provides for a minimum royalty in an amount different from

the delay rental for years within the primary term, guaranteeing payment

during the primary term even if drilling operations are undertaken. Such a

provision is inadvisable as an unnecessary complication of rental payments

during the primary term. Otherwise, it is similar in effect to Option.1,

except for the inclusion of shut-in well royalties. If royalties are charged

for shut-in wells, they should be included here. One possible modification of

this provision would be to charge the royalty on a per acre per year basis, if

delay rentals are also charged on a per acre basis.

F. Reduction of Royalty (Optional)

After initial production has occurred for two years from the field
in which the leased area is located, the State in its discretion, may reduce
Lessee's obligations to pay royalty on all of the leased area or on any
trace or portion of the leased area segregated for royalty purposes upon
(1) request by the Lessee, (2) a clear showing by the Lessee that the revenue
from all oil, gas, and associated substances produced from the field is
insufficient to produce a reasonable rate of return with respect the Lessee's
total investment in the field, and (3) a clear showing by the Lessee that a
reduction in royalty will increase total production from the field.

F-19

[Comment]

During the life of a producing field, production is apt to decline to the

point where the lessee's after-royalty revenues would not be sufficient to

cover expenses. In such cases the royalty, if not lowered, would cause the

lessee to abandon the field entirely at a net loss to both society and the

lessor. Similarly, a marginal field may not be profitable to develop with a

royalty of 1/6, but might be if the royalty were 1/10. This clause, found in

the Alaska standard lease, empowers the state to lower the royalty in such

cases. In practice, however, royalties are seldom reduced; although the U.S.

Department of the Interior has had authority to lower royalties since 1953, it

has never exercised this authority, at least through 1978.

Section 6: Share of Net Profit. Lessee shall pay to the State
percent ( %) of the net profits from the operations under this lease. Net
profits shall be determined as provided and paid in the manner prescribed in
the net profits accounting procedure which is Exhibit - to this lease.

[Comment]

A net profits share provision may be either an alternative or supplement

to a royalty provision. While most states charge only royalty payments,

California relies on a net profits share alone, and Alaska requires both types

of payment. Although the above provision (from California's standard lease)

may appear to be simpler than a royalty provision, the appendix to the lease

consists of 39 pages of accounting procedures for determining "net profits,"

listing in detail the expenses which may or may not be deducted from the

revenues collected. Similarly, Alaska's calculation of net profits is based

on a complicated statutory provision.

Section 7. Extension of Lease.

(a) If prior to discovery and production of oil or gas on said land or
on acreage pooled therewith, Lessee should drill a dry hole or holes thereon,

F-20

or if after discovery and production of oil and gas the production thereof
should cease from any cause, this lease shall not terminate if Lessee
commences operations for drilling or reworking within ninety (90) days
thereafter.

(b) If such dry hole(s) or cessation occurs within the primary term, the
lease will not terminate if Lessee commences or resumes the payment or tender
of rentals or commences operations for drilling or reworking on or before the
rental paying date next ensuing after the expiration of ninety (90) days from
the date of completion of the dry hole or cessation of production.

(c) If at the expiration of the primary term, or any extension thereof,*
or thereafter, oil or gas is not being produced on said land, or on acreage
pooled therewith, but Lessee is then engaged in drilling or reworking
operations thereon or shall have completed a dry hole thereon within ninety
(90) days prior to the end of such term, the lease shall remain in force so
long as operations on said well or on any other well are (re)commenced within
ninety (90) days of the last cessation or dry hole completion and are prose-
cuted with no cessation of more than ninety (90) consecutive days. If such
operations, drilling, or reworking result in the production of oil and/or gas,
the lease shall remain in force so long thereafter as oil and/or gas is
produced in paying quantities from said land or acreage pooled therewith, or
as the provisions of this Section keep it in force.

[Comments]

This section includes three separate clauses which are usually included

in oil and gas leases. The first, known as the "continuous operations

clause," keeps the lease in effect after a well ceases to produce by allowing

the lessee to return to operations within a given period of time. The "dry

hole clause" similarly allows continuation of operations even after work

stoppage resulting from drilling a dry hole. The third clause, the "well

completion clause," expressly provides for the completion of well drilling at

the end of the primary term. The amount of delay allowed is normally the same

number of days for each of these provisions. Ninety days was used here

because the existing North Carolina lease allows ninety days, but sixty days

is more common.

F-21

Section 8: Duties of Lessee.

Lessee agrees to develop and manage the leased area with due diligence
consistent with accepted operation and development practices and in accordance
with the interests of both Lessor and Lessee, the provisions of this lease,
and the laws, rules, regulations and executive orders of the United States and
the State of North Carolina. Lessee agrees to conduct such development in a
manner recognized as adequate and proper in order that Lessor may receive as
early as possible the royalties provided for in this lease. Such conduct
shall include, but not be limited to:

a. Diligent attempts to drill all exploratory holes to basement, or
crystalline rock, in order to fully test the oil and gas potential of the
entire sedimentary section at the well site;

b. After due notice in writing, diligent drilling and production of such
other wells as the Department may reasonably require in order that the leased
area or any part thereof may be properly and timely developed and produced in
accordance with good operating practice;

c. At the election of Lessee, drilling and production of other wells
in conformity with any system of well spacing or production allotments
affecting the area, field or pool in which the leased area or any part thereof
is situated, which is authorized or sanctioned by applicable law or
regulation, or by the Department;

d. The use of all reasonable precautions by Lessee to prevent waste of
oil and gas in the leased lands and to prevent the entrance of water through
wells drilled to the oil or gas-bearing strata that may destory or injure the
oil or gas deposits.

[Comment]

This section is based on the existing North Carolina lease section on

wells, but excludes the provision on offset wells, which has been included

instead as a separate section (see Section 9: Offset Wells, below). A "due

diligence" clause excerpted from Alabama's standard lease has been added.

Also added is a waste and seepage provision from California; inclusion of this

may, however, be redundant, since North Carolina oil and gas regulations

already cover this topic.

Subsection b, as worded in North Carolina's current lease and reproduced

here, might be interpreted to allow the lessor to dictate how the leased area

will be explored. This is not done in most other jurisdictions. Before

F-22

incorporating this provision into the lease an alternative allowing the state

to require drilling only for more specifi c purposes, such as prevention of

waste, seepage, or drainage, should be considered.

Section 9: Offset Wells.

a. If, at any time during or after the primary term, oil, gas or any
other liquid or gaseous hydrocarbon mineral should be produced in paying
quantities in a well on land privately owned or on State land leased at a
lesser royalty, which well is within any spacing or pooling unit distance
established by the State Oil and Gas Board and draining the area included
herein, the Lessee shall, within sixty (60) days after such initial production
on such other land, begin in good faith and prosecute diligently the drilling
of an offset well on the leased area, and such offset well shall, be drilled to
such depth as may be necessary to prevent undue drainage of the leased area.
Lessee shall use all means necessary in a good faith effort to make such off-
set well produce oil, gas or other liquid or gaseous hydrocarbon minerals in
paying quantities.

b. In addition to the specific offset drilling obligation above provided
for wells within spacing or pooling unit distance, Lessee agrees to drill any
and all wells necessary to protect the leased area from drainage of oil, gas
or other liquid or gaseous hydrocarbon minerals by a well or wells on adjoin-
ing land privately owned or on State land leased at a lesser royalty, or to
take any other steps reasonably necessary to protect the leased area against
such drainage including, but not limited to obtaining the formation of appro-
priate drilling or production units.

c. In lieu of commencing operations for an offset well to State lands
leased at a lesser royalty burden or to private lands, as above provided,
Lessee may, at Lessee's option, commence compensatory payments equal to the
royalties herein provided, computed on the value of one-half (1/2) of the oil,
gas, or other liquid or gaseous hydrocarbons produced by the well in question,
on and after the date operations would have otherwise have been commenced,
value to be determined in accordance with the provisions of Section 5
[Royalties] of this lease. Such payments may be commenced within sixty (60)
consecutive days after the date operations would otherwise have been comr.-
menced, but shall include any accrued compensatory payments. Thereafter,
payments shall be due monthly in accordance with Section 5. Lessee shall not
be in default in either commencing compensatory payments or in making further
payments as above provided if despite good faith and due diligence Lessee is
unable timely to obtain the production information on which such payments are
to be based. In any such case, however, Lessee must on or before the due date
of the payments, notify the Lessor in writing of Lessee's inability to make
such payment, the reasons therefor, and Lessee's intent to make such payment
at the earliest reasonable time. Compensatory payments may be continued, at
Lessee's discretion, for not more than one year from the date on which offset
operations would otherwisehave been commenced. At the end of that time, or

F-23

within thirty (30) consecutive days from the end of any lesser period for
which payments are made, Lessee shall comply with this offset obligation if
the producing well continues to produce in paying quantities and the other
conditions making this obligation operative are existent.

The compensatory payments required hereby are in addition to, and not in
lieu of, any rental or other payment required by any other provision of this
lease. The right to make compensatory payments is intended to permit Lessee
to evaluate further the producing well, and the making of such payments shall
not of itself be sufficient to maintain this lease in force and effect during
the period allowed therefor if other payments required during this same period
are not made; however, the making of any such compensatory payments shall not
prejudice Lessee's right to rebut any of the above enumerated presumptions.

[Comment]

It is common in oil and gas leases to have provisions requiring offset

wells under certain circumstances. The existing North Carolina lease form has

a clause resembling an offset well clause but not such a clause per se. While

subsections (a) and (b) here are typical of offset provisions,.subsection (c)

is more detailed than most such provisions for compensation as an alternative

to offset drilling. Provisions of subsection (c) regarding nonpayment and the

one-year limit on monetary compensation are optional and may be altered or

eliminated. It might also be advisable to better define "draining" and

"drainage" as used in subsections (a) and (b), either within those subsections

or in a separate "Definitions" section. One such definition commonly used

requires that the well on adjoining property "produce oil, gas, or other

liquid or gaseous hydrocarbons in paying quantities for twenty (20) days

(which need not be consecutive) during any period of thirty (30) consecutive

days, or produces its monthly allowable during such thirty (30) consecutive

day period."

Section 10: Directional Drilling. This lease may be maintained in
effect by directional wells whose bottom hole location is on the leased area
but.that are drilled from locations on other lands not covered by this lease.
In those circumstances, drilling shall be considered to have commenced on the
leased area when actual drilling is commenced on those other lands for the

F-24

purpose of directionally drilling into the leased area. Production of oil or
gas from the leased area through any directional well surfaced on those other
lands, or drilling or reworking of that directional well, shall be considered
production, drilling, or reworking operations on the leased area for all
purposes of this lease. Nothing contained in this Section is intended to or
shall be construed as granting to Lessee any interest, license, easement, or
other right in or with respect to those lands in addition to any interest,
license, easement, or other right that Lessee may have lawfully acquired from
the State or from others.

[Commentl

This section is taken directly, with a few minor changes, from the

Drilling section of the existing North Carolina lease. Such a directional

drilling clause is standard in oil and gas leases.

Section 11: Repressuring; Use of Water.

Lessee shall have the use, free from royalty payments, of oil and gas
produced from the leased premises for operations essential to the production
of oil and gas hereunder and for repressuring the oil and gas bearing forma--
tions. For the latter purpose, such gas may be injected at any point in the
same pool, as the term "pool" is defined by G.S. 113-389.

Lessee shall have the privilege to use, free of cost, such quantities of
water from the leased premises as are reasonably necessary for all operations
hereunder, except water from the wells of Lessor. All of the rights and
privileges of this Section are specifically made subject to compliance with
all applicable laws,.rules and regulations of the State as may be in effect at
the time of exercising these rights and privileges, even if such laws, rules
and regulations prohibit actions allowed by the terms of this Section.

[Comment]

The language of this section is taken entirely, with some minor editorial

changes, from the existing North Carolina lease. The repressuring provision,

though not commonly expressed in other states, is usually implied by royalty

clauses exempting from royalties that oil and gas necessary for production

operations; to that extent, this clause may be redundant of the royalty

provisions. Repressuring may, however, deserve separate mention since it is

often essential to encourage the most efficient production of oil and gas.

Water use provisions are common, though they may vary with the particular

circumstances of the lease.

F-25

Section 12: Lessor's Right to Regulate Well-Spacing and Drilling:

Lessor shall have the right to determine the spacing of wells and the
rates of production and drilling of wells to prevent the waste of oil and gas
and promote the maximum economic recovery of oil or gas from, and the
conservation of reservoir energy in, each zone or separate underground source
or supply of oil or gas covered in whole or in part by this lease. Lessee
agrees to comply with all laws, rules and regulations generally applicable to
the spacing of wells and the rates of production and drilling of wells, as
well as with any specific restrictions Lessor may impose on the premises or
reservoirs included in this lease.

. [Comment]

The first part of this provision was taken from California's standard

lease. The second part is the converse of the State's right, requiring com-

pliance by the lessee.

Section 13: Shut-in Wells.

(a) If at the expiration of the primary term, or at any time after its
expiration, a well capable of producing gas or oil in commercial quantities is
closed so that production ceases (shut-in), Lessee shall immediately notify
the Department of the date that such well was shut-in. For the purpose of
this lease, said well shall be considered a producing well, and shall be
treated in the manner set forth in Section 5E above [Minimum Royalty].

[Comment]

Although the existing North Carolina lease does not restrict its shut-in

clause to the period after the primary term, the majority of other states do.

(Louisiana is one exception.) Eliminating sucha restriction in this pro-

vision is one option. Other states also provide for shut-in royalties at

twice the rate of delay rentals; however, this provision occurs only in those

states where the minimum royalty is also double the delay rental. Louisiana

has established a per acre rate for shut-in payments. Some states also limit

their shut-in provisions to gas-producing wells.

(b) If production commences on a shut-in well during any given year, or
if for some other reason the well ceases to be a shut-in well during any

F-26

given year, Lessee shall pay to Lessor a pro-rated amount of the royalty for
that year on the acreage held. At no time, however, shall the total payment
for any year be less than that provided for in Section 5E above [Minimum
Royalty].

(c) If, at any time while this lease is being maintained in force and
effect under the provisions of this section, gas or oil should be produced and
sold or used in paying quantities from a well or wells completed in the same
producing reservoir on adjacent state-owned lands leased at a lesser royalty
or on adjacent private lands, which are draining the leased premises, the
right to extend this lease by the shut-in royalty payments above shall cease
at the expiration of the last 12-month period for which payment has been made.
Thereafter, Lessee may maintain this lease in force and effect only by opening
said well as an offset well or by paying compensatory royalty to Lessor, as
provided for in Section 7, above [Offset Wells].

[Comment]

This important provision for compensatory royalties in the case of shut-in

wells is absent from the existing North Carolina lease. Although compensatory

royalties are discussed above under the provision for offset wells, it is

vital that they be applied to shut-in wells as well.

(d) Lessee hereby agrees that it shall attempt to market such gas or
oil mentioned in subsection (b) above in a manner that would be most bene-
ficial to Lessor. Nothing herein shall relieve Lessee of the obligation
of reasonable development of the leased premises, nor of the obligation to
drill offset wells as required by Section 7, above (Offset Wells].

[Comment]

This is an expanded version of a provision which is in the current North

Carolina lease. A reference to the duties of development and of drilling

offset wells is included to reinforce their importance.

Section 14: Pooling and Unitization.

Option 1:

Lessee's right to pool or unitize the leasehold estate and mineral
estate covered by this lease with other land, lease or leases into one or more
operating units for the production of oil and gas, or separately for the
production of either shall be governed by rules and regulations promulgated by
the Secretary of the Department of Natural Resources and Community Development
as are in effect at the time of the proposed pooling or unitization.

F-27

[Comment]

it is common practice to include a unitization clause in the lease, as

North Carolina has done in the past. This clause is taken almost verbatim

from the existing lease. While pooling and unitization both refer to the

combination of leases and land for more effective and efficient production,

pooling specifically means the combination of enough land to form a single

well-drilling unit, and unitization refers to a larger field-wide or partial

field-wide operation.

Option 2:

Lessee, at its option, is hereby given the right and power to pool or
combine the acreage covered by this lease or any portion thereof with other
land, lease or leases in the immediate vicinity thereof, when in Lessee's
judgment it is necessary or advisable to do so in order properly to develop
and operate said premises in compliance with the spacing rules of the Depart-
ment or other lawful authority, or when to do so would in the judgment of
Lessee promote the conservation of the oil and gas in and under and that may
be produced from said premises. Lessee shall execute in writing an instrument
identifying and describing the pooled acreage. The entire acreage so pooled
into a tract or unit shall be treated, for all purposes except the payments of
royalties on production from the pooled unit, as if it were included in this
lease. If production is found on the pooled acreage, it shall be treated as
if production is had from this lease, whether the well or wells be located on
the premises covered by this lease or not. Under this lease, Lessor shall
receive on production from a unit so pooled only such portion of the royalty
stipulated herein as the amount of acreage placed in the unit or his royalty
interest therein on an acreage basis bears to the total acreage so pooled in
the particular unit involved.

[Comment on Option 21

This option, an example of a basic pooling clause, is more inclusive than

Option 1. If a more detailed clause such as this one is desired, it should be

revised to summarize the regulations in effect at the time of leasing and any

additional requirements deemed necessary. Considering the vagueness of North

Carolina's pooling regulations (15 NCAC 5D .0006), the lease provision should

be as comprehensive as possible. If, however, the regulations are made more

comprehensive, Option 1 would be preferable to Avoid conflicts between the

F-28

lease and the regulations. In any case, the regulations and the lease should

together cover: 1) basis and authority of the lessee to pool or combine

acreage; 2) the method of designation of the pooled acreage; 3) the effect of

production within the unit upon acreage within and outside the unit; and

4) the apportionment of royalties among parties to the pooling or unitization

agreement.

Option 3:

(a) Lessee may unite with others, jointly or separately, in collec-
tively adopting and operating under a cooperative or unit agreement for the
exploration, development, or operation of the pool, field, or like area or
part of the pool, field, or like area that includes or underlies the leased
area or any part of the leased area whenever the State determines and
certifies that the cooperative or unit agreement is in the public interest.

(b) Lessee agrees, within six months after demand by the State, to
subscribe to a reasonable cooperative or unit agreement that shall adequately
protect all parties in interest, including the State. The State reserves the
right to prescribe such an agreement.

(c) With the consent of Lessee, and if the leased area is committed
to a unit agreement approved by the State, the State may establish, alter,
change, or revoke drilling, producing, and royalty requirements of this lease
as the State determines necessary or proper to secure the proper protection of
the public interest.

(d) Except as otherwise provided in this subparagraph, where only a
portion of the leased area is committed to a unit agreement approved or pre-
scribed by the State, that commitment constitutes a severance of this lease as
to the unitized and nonunitized portions of the leased area. The portion of
the leased area not committed to the unit will be treated as a separate and
distinct lease having the same effective date and term as this lease and may
be maintained only in accordance with the terms and conditions of this lease,
statutes, and regulations. Any portion of the leased area not committed to
the unit agreement will not be affected by the unitization or pooling of any
other portion of the leased area by operations in the unit, or by suspension
approved or ordered for the unit. If the leased area has a well certified as
capable of production in paying quantities on it before commitment to a unit
agreement, this lease will not be severed. If any portion of this lease
included in a participating area formed under a unit agreement, the entire
leased area will remain committed to the unit upon contraction of the unit and
this lease will not be severed.

F-29

[Comment on Option 31

This clause, from Alaska, gives both the lessee and the State the power

to pool or unitize leased areas, and contains provisions that, if not included

in the regulations, would be important to include. A-particularly important

provision is subparagraph (d), a severance clause which designates the

pooled area as a separate tract for lease purposes, since different terms

might be advisable for the newly pooled area.

Section 15: Severance of Minerals.

It is understood and agreed by the parties hereto that the title to any
and all minerals coveted by this agreement shall be and remain in the State of
North Carolina until such minerals are severed from the lands covered by this
agreement.

[Comment]

This provision is included in the existing North Carolina lease and may

clarify some misconceptions as to the relationship created by the lease. The

majority of other states, however, do not have a similar provision.

Section 16: Inspection.

Lessee agrees to keep open at all reasonable times for the inspection by
any duly authorized representative of Lessor: the leased area; all wells,
improvements, machinery and fixtures thereon; and all books, accounts, and
records relating to operations, surveys, or investigations on or with regard
to the leased area, or under the lease.

[Comment]

This provision, taken from the most recent North Carolina lease, is a

standard part of any state oil and gas lease. It can be included as a

separate provision or can be subsumed as a subsection of the recordkeeping and

reporting requirements (See Section 17).

F-30

Section 17: Records and Reports.

(a) Lessee shall provide the Department accurate reports of expenses and
expenditures incurred pursuant to drilling test wells under this lease or in
performing other geological and geophysical work under this lease. Said
report shall be provided by Lessee within thirty (30) days after the cour-
pletion of any work performed hereunder. The Department shall have the right
at any time to require in writing that Lessee submit a written report of
expenses and expenditures within thirty (30) days after receipt of said
request.

(b) In addition, Lessee shall furnish to the Department copies of all
geological, geophysical, or geochemical data, results, and interpretations
within ninety (90) days after the completion of said work, or within ninety
(90) days after the termination of the lease, whichever comes first. To the
extent these data, results, and interpretations are deemed proprietary or
confidential in nature by Lessee, Lessee may request Lessor to treat the
information as confidential for a period not to exceed five (5) years. To the
extent it may legally do so, Lessor will grant the request if satisfied that
the information is proprietary and confidential in nature. Upon an agreement
as to confidentiality, Lessor shall have the right to use the information, but
will not allow its inspection, examination, or copying as a public record
unless required to do so by a court of competent jurisdiction.

(c) No part of this section is intended in any way to change or abrogate
the requirements of the laws, rules, and regulations of the State of North
Carolina. If any inconsistency should exist between this Section and said
laws, rules, and regulations, the latter shall govern.

(d) Lessee shall assume no responsibility or liability for the interpre-
tations furnished to Lessor,pursuant to the terms of this Section.

[Comment]

A record-keeping provision is a well-established part of all oil and gas

leases. Some alternatives to the continuous submission of reports and records

to the Department would be to require that such recordsland reports be sub-

mitted at periodic intervals (e.g., monthly, bi-monthly, quarterly), that such

records and reports be kept by the lessee to be submitted to the Department

only upon request of the Department, or that they be kept available for State

inspection.

Other states have provided in the lease a more specific list of the

records and reports required; if the State is interested in any specific data

it would be wise to list it in an "including but not limited to phrase.

F-31

One possibility would be to require that some important documents be submitted

on a regular basis and that others be retained by the lessee for inspection or

submittal upon request by the Department.

The five-year period for confidentiality was chosen because it is the

period used in the existing North Carolina lease. This period varies among

states, ranging from three years to ten years.

Subsection (d) was included here because it is part of the existing North

Carolina lease. A similar provision does not appear in the leases of other

states and its purpose and necessity are doubtful.

Other requirements may be made.under this section. Florida's lease, for

instance, requires the lessee to furnish annual reports both estimating "the

quantity of proved reserves of oil and gas underlying the lands covered by

this lease," and giving the status of operations on the land.

Section 18: Abandoned Wells.

In the event any well is drilled on the leased premises and, after being
drilled, is found to be dry or should later become dry, or the use thereof be
discontinued for one year for any reason, Lessee shall permanently close and
seal such well to prevent seepage or leakage therein of any water or brine, in
compliance with the regulations established by the Department. Provided,
however, it is understood by both parties that the provisions of this section
shall not apply to shut-in wells.

[Comment]

This section, taken from the existing North Carolina lease, complements

both the dry hole clause in Section 6 and the oil and gas regulations promul-

gated by the Department. However, this provision contradicts the existing

regulation requiring that a well be plugged after thirty days of non-operation

(15 NCAC 5D .0009). The time period in the lease should be changed to corres-

pond with the regulation, or this section should be abandoned in favor of the

regulations.

F-32

Section 19: Removal of Property.

(a) Upon the termination or surrender of this lease in whole or in part,
as provided in this lease, Lessee shall within a period of one (1) year there-
after remove from the premises no longer subject to the lease all structures,
machinery, equipment' tools, and materials which can safely be removed. Such
removal shall be in accordance with applicable regulations and orders of the
Department and shall concur with regulations regarding casing, plugging, and
shut down of wells. However, Lessee may continue with the approval of the
Department to maintain any such property on the leased area for whatever
longer period it may be needed, as determined by the Department, for producing
wells or for drilling or producing on other leases. Upon expiration of the
period provided for herein, at the option of the State, any machinery, equip-
ment, tools, and materials that Lessee has not removed from the leased area or
portion of the leased area becomes the property of the State or may be removed
by the State at Lessee's expense.

[Comment]

This is a slightly modified version of North Carolina's existing provi-

sion. Other states provide for a shorter time period (e.g., 120 days) or

designate that equipment be removed within a "reasonable time." In North

Carolina, where it is unlikely that another lessee will want to do work in the

same area immediately, the one year period should be both reasonable and

adequate, and is therefore better than either a shorter period (with possible

extension) or an ambiguous "reasonable time." The final sentence of this

subsection, not currently included in North Carolina's lease, is a clause used

in some other states and should be considered here.

(b) Upon the termination of this lease for any cause, Lessee shall not,
in any event, be permitted to remove the casing or any part of the equipment
from any producing, dry, or abandoned well or wells without the written con-
sent of the Department and concurrence with applicable regulations regarding
casing, plugging, and shut-down of wells; nor shall Lessee, without the
written consent of the Department remove from the leased premises the casing
or any other equipment, material, machinery, appliances or property owned by
Lessee and used by Lessee in the development and production of oil or gas
therefrom until all dry or abandoned wells have been plugged and until all
slush or refuse pits have been properly filled and all broken or discarded
lumber, machinery, or debris shall have been removed from the premises to the
Department's satisfaction.

F-33

[Comment]

This subsection, based on the Texas lease, makes the removal of equipment

dependent on Departmental approval, reaffirming the administrative regulations

requiring the same. The Departmentfs approval is desirable to assure that the

wells are completely shut down before equipment is removed. Together,

subsections (a) and (b) put the lessee under an affirmative duty to remove its

equipment but require state approval before the duty is undertaken, so that

clearance of the leased area can occur and the buildup of debris can be

prevented in accordance with prescribed rules and regulations.

Section 20: Compliance With Laws_and Regulations; Interference With Others.

(a) All expressed or implied covenants of this lease shall be subject
to all applicable Federal and State laws, executive and administrative orders,
rules and regulations in effect on the effective day of this lease and,
insofar as is constitutionally permissible, after the effective date of this
lease. Lessee shall specifically comply with all regulations issued by the
Department relating to exploration, development, and production, including but
not limited to those regarding bonding, exploration plans, drilling, casing
and plugging of wells, and the prevention of waste. Nothing herein shall be
deemed to restrict the power of the State or of its agencies or subdivisions
to enforce all provisions of law and all applicable regulations; the proce-
dures applicable to the enforcement of a,ny law, rule, or regulation shall be
in the manner set forth therein.

(b) This lease is made subject to the superior rights of navigation of
the waters herein described. No structure shall be built, nor any dredging
and filling operations shall be undertaken therein until such structure or
operations have been authorized by the governments of North Carolina and the
United States and the proper officials thereof where such authorization is
required by law, order, or governmental regulations.

(c) This lease is also made subject to all leases, easements, permits,
or licenses presently in existence to which Lessor is a party. This lease
shall be subject to any oyster or clam bed lease heretofore granted by the
Secretary of the Department of Natural Resources and Community Development
(formerly the State Board of Conservation and Development) or any other
authorized agency.

(d) Lessee hereby agrees, as one of the obligations of this lease, that
in exercising its rights and duties under this lease it will take all prudent
or required precautions to prevent pollution of the land, air, or waters, of
the State of North Carolina. Lessee will comply with and be subject to all
applicable laws and regulations validly adopted or issued by the State of

F-34

North Carolina, or its agencies, or by the United States, or its agencies.
Lessee agrees to procure all necessary permits, licenses, or certifications
before undertaking any activity which may be harmful to the environment and
may require such permit, license, or certification. It is specifically
provided that the Department shall have the right and authority to inspect any
part of Lessee's operations at any reasonable time to determine whether any
pollution of the State's surface or ground waters is resulting from such
operation.,

(e) The prospecting, exploration, mining, and concentrating operations
of Lessee within the exploration area shall be performed in a good and work-
manlike manner in accordance with established practices and in a manner that
will not interfere with navigation along the channels of the waterways within
the prospecting area or unreasonably interfere with navigation elsewhere,
including wharves and docks. No such operations shall be carried out in such
a manner as to destroy or imperil any highway, railway, or bridge within the
lease area or to interfere with property or equipment used by commercial
fishermen within the lease area.

[Comment]

Sever al sections of the existing North Carolina lease were re-ordered and

consolidated to create this section. Subsection (c) is unique to'North

Carolina's lease and might cause conflicts with owners of surface leases on

the lease's covered acreage by implying that surface leases have superior

rights. Depending on state policy in regard to this type of conflict, the

state should consider deleting this subsection (see Chapter 5). Subsection

(d) on pollution abatement may be highlighted in a section of its own if so

desired. Likewise, subsection (e), a separate section in the existing lease,

may be so separated. There is no analogous provision to subsection (e) in the

leases of other states, but it is probably valuable to include it here.

Section 20: Rights of Municipalities and Other Parties.

This agreement is made subject to any and all rights and interests
of any municipality which may be located within theboundaries or have
jurisdiction over the lease area herein described and is further made subject
to all rights, title and interest of individuals which may be of record.

F-35

Section 21: Force Majeure; Suspension.

Option 1:.

(a) If, prior to discovering oil, gas, or other minerals covered
hereby, Lessee is prevented from complying with any express or implied
covenant of this lease, from conducting drilling operations thereon, or from
attempting to produce oil or gas therefrom, after good faith effort,
by reason of war, rebellion, riots, strikes, vandalism, acts of God, or any
valid order, rule or regulation of government authority, including regulations
for obtaining required federal or state environmental or other permits, then
while so prevented, Lessee's obligation to comply with such covenant shall be
suspended and this lease, and the time for complying with any provision
hereof, shall be extended while and so long as Lessee is prevented, by any
such cause, from drilling, reworking operations, or attempting to produce oil
or gas from the leased premises; provided, however, that nothing herein shall
be construed to suspend the payment of delay rentals in order to maintain this
lease in effect during the primary or extended term in the absence of such
drilling or reworking operations or production of oil or gas; and further
provided, that in the event Lessee invokes the provisions of this paragraph to
excuse performance by reason of failure or inability to obtain required
Federal or State permits or authorizations Lessee shall produce and submit to
Lessor all data, documents or other information required by Lessor to
establish the good faith attempts of Lessee to obtain said permits or
authorizations.

(b) If oil, gas or any other mineral covered hereby is discovered but
production is prevented by any of the causes in Subsection (a) above, this
lease shall be considered producing and shall continue in full force and
effect until Lessee is permitted to produce said minerals, and as long there-
after as same actually is produced in paying quantities; provided, however
that Lessee, as,.an express condition for the extension of the lease without
production, shall pay to Lessor: (i) for an oil or other liquid hydrocarbon
well, the sum of Dollars ($ ) Iper annum
for each acre of the leased area; or (ii) for a gas well, The shut-in gas
royalty specified above, payment on both cases to be made within ninety (90)
consecutive days from the date that production is prevented and annually upon
such payment date until production is resumed.

[Commment]

This clause is taken from Mississippi's standard oil and gas lease and

has the effect of suspending the obligations of the lease for any delay caused

by the listed reasons. Under this option, payment is required to keep the

lease in effect during both the primary term and thereafter, with different

formulas used for payment depending on during which phase of exploration and

development the delay may occur. While this double standard may cause

confusion, it should be consistent with the rest of the lease.

F-36

Option 2:

Should Lessee be prevented from complying with any express or implied
covenant of this lease, from conducting drilling operations thereon, or from
producing oil and/or gas therefrom, after effort made in good faith, by reason
of war, rebellion, riots, strikes, acts of God or any order, rule or regula-
tion of governmental authority, then while so prevented, Lessee's obligation
to comply with such covenant shall be suspended upon proper and satisfactory
proof presented to Lessor in support of Lessee's contention, and Lessee shall
not be liable for damages for failure to comply therewith; this lease shall be
extended while and so long as Lessee is prevented, by any such cause, from
drilling, reworking operations or producing oil and/or gas from the leased
premises; provided, howeveri that nothing herein shall be construed to suspend
the payment of rentals during the primary or extended term, nor to abridge
.Lessee's right to a suspension under the terms of this lease.

[Comment]

This option, more concisely stated than Option 1, comes from Texas.

Although it also provides for rental payments during a delay, it relies on

other provisions in the lease to delineate these payments. It emphasizes,

instead, suspension of lessee's duties to perform under the lease. It is wise

to include a provision requiring some proof of the cause for delay, as this

option does; however this option's failure to specifically include government

delay in the processing of permits as a justified cause for delay may create

problems.

Option 3:

The obligations imposed upon Lessee by this lease may be suspended when-
ever Lessee is prevented from complying with them by wars, strikes, riots,
acute and unusual labor or material shortages, acts of God, laws, rules and
regulations of any federal, state, county or municipal agency or by other
unusual conditions that are beyond the control of Lessee., In order for any
obligation imposed upon Lessee to be suspended, Lessee must notify the State
in writing as soon as possible that a condition warranting suspension has
arisen. The notification shall state the nature of the condition, an estimate
of the condition's duration and the steps to be taken by Lessee to eliminate
the condition. Lessee shall use its best efforts to eliminate the condition
and notify the State in writing as soon as the condition no longer exists.

F-37

[Comment]

This option, taken from California's lease, varies from the others in

that it has an open ended "other unusual conditions" provision; while it may

be useful to include these unlisted, but nevertheless justifiable causes for

delay, it might also be a source of potential conflict when a difference of.

opinion arises as to whether a cause is justifiable. This clause also has the

effect of suspending all obligations of the lessee, delay rental payment

included. One value of this clause is the diligence required on lessee's part

in trying to eliminate the condition causing delay.

Option 4:

Should Lessee be prevented from complying with any express or
implied covenant of this lease, from conducting drilling operations or pro-
ducing any products as herein defined from the leased premises, after effort
made in good faith, by reason of war, rebellion, riots, strikes, acts of God
including but not limited to fire, storms, floods, washouts, landslides and
lightning, or any laws, acts, orders, rules, regulations or demands of govern-
mental authority (including regulations for obtaining required State or
Federal environmental or other permits), then while so prevented, Lessee's
obligation to comply with such covenant shall be suspended upon proper,
satisfactory and convincing proof presented to Lessor in support of Lessee's
contention; and Lessee shall not be liable for damages for failure to comply
therewith. This lease shall be extended while and so long as Lessee is
prevented, by any such cause, from drilling, reworking operations or producing
oil and/or gas from the leased premises, provided, however, that nothing
herein shall be construed to suspend the payment of rentals during the primary
or extended term, nor to abridge Lessee's right to a suspension under any
provision herein or under any applicable statute of this state. Lessee shall
be required at all times to use reasonable diligence to overcome such causes
as described above as promptly as circumstances will permit, and to recommence
operations hereunder as soon as is reasonably possible.

[Comment]

There is a partial force majeure clause in the existing North Caro-lina

lease; this option expands upon that one to provide more complete coverage.

Provisions have been added here to provide for delay due to acts of God and to

specify that delay due to procurement of permits is included as a government

action. It has become common to include a f orce majeure clause in oil and gas

F-38

leases, out of fairness to the lessee acting in good faith. While the burden

is still on the lessee to prove a force majeure to the lessor, the lessee is

given some relief from its obligations if such cause for delay can be proven.

The clause included here is a combination of the clauses of several states,

which vary as to their specificity in listing acts of God and specific inclu-

sion of delay due to procurring permits. Since possible conflicts within the

lease between the force majeure clause and other claus es dealing with delays

might arise, it might be wise to include in those other clauses mention of

force majeure.

Section 23. Severability.

Option 1:

If it is finally determined in any judicial proceeding or by agreement of
the parties hereto that any provision of this lease is illegal or unconsti-
tutional, Lessor and Lessee may jointly determine and agree by a written
amendment to this lease that, in any consideration of the promises, terms,
conditions, and covenants contained in that written amendment, the invalid
portion will be treated as severed from this lease and that the remainder of
this lease, as amended, will remain in effect.

Option 2:

In the event that any provision of this lease is finally determined
to be illegal or unconstitutional in any judicial proceeding or by agreement
of the parties hereto, its nullity shall in no way impair the validity of any
other portion of the lease not declared invalid; provided, that Lessee shall
not directly or indirectly institute or cause to be instituted any action
seeking to declare the nullity or the unenforceability of this lease as a
whole.

[Comment]

Ths existing North Carolina lease has no severability provision; the

effect of this may be that the entire lease will be voided if any provision is

declared illegal. If this possibility is to be avoided, one of the above

severability clauses sho uld be included in the lease. If at the time of

signing the original lease it can be agreed that the provisions of the lease

F-39

will be severable, the second option should be chosen; otherwise, the first

option, making severability optional, should be selected.

Section 24. Indemnification.

Option 1:

Lessee agrees to indemnify and save Lessor harmless against and from
any and all claims of any nature whatever, including without limitation claims
for loss or damage to property or injury to persons, caused by, or resulting
from, any operation on the leased area conducted by or on behalf of Lessee;
provided that Lessee shall not be held responsible to Lessor under this
subsection for any loss, damage, or injury caused by, or resulting from:

(a) any negligent action of Lessor other than the exercise or per-
formance of (or the failure to exercise or perform) a discretionary
function or duty on the part of a State agency or an employee of
such an agency, whether or not the discretion involved is abused;
or

(b) Lessee's compliance with an order or directive of Lessor against
which an appeal by Lessee under applicable rules and regulations is
filed before the cause of action for such a claim arises and is
pursued diligently thereafter.

[Comment]

This detailed clause, taken from the existing North Carolina lease, is

probably the fairest possible provision to the lessee, making the lessee

liable only for what it may expect to the liable for. Other states, however,

employ a blanket indemnification clause, such as Option 2.

Option 2:

Lessee shall indemnify the State of North Carolina, its officers,
agents and employees against all claims, demands, causes of action or liabili-
ties of any kind which may be asserted against or imposed upon the State of
North Carolina, its officers, agents or employees, by any third person or
entity arising out of or connected with the issuance of this lease, operations
hereunder, or the use by Lessee, its agents, employees or contractors of the
leased lands.

[Comment]

This is a more common form of indemnification clause, placing all

liability on the lessee.

F-40

Some additional provisions, taken from the California standard oil and

gas lease, might be considered as optional amendments to the indemnification

clause. These regard liability for damage to the lessor's property from the

lessee, and liability insurance for the lessee. If these options are

included, the Section should be renamed Liability; the provisions might be

drafted as follows:

Lessee shall be liable to the State for all damage to any reservoir
underlying the leased lands and any loss of oil, gas or other hydrocarbon
substances to the extent that they are caused by the negligence of, or the
breach of any provision of this lease by, or noncompliance with any applicable
statutes or regulations by Lessee, its employees, servants, agents or con-
tractors. Nothing in this lease shall diminish any other rights or remedies
which the State may have in connection with any such negligence or breach.

Lessee shall furnish upon execution of this lease a certificate showing
that at all times throughout the life of this lease, Lessee.is insured against
damages to third persons and their property resulting from an oil spill or
other pollution caused by operations under this lease. The insurance shall be
for an amount not less than dollars ($ for each
occurrence. The minimum amount may be raised by the State if economic
conditions change. The certificate of insurance coverage shall include the
State of North Carolina as a named insured, or shall demonstrate to the -
satisfaction of the State that Lessee is capable of self-insuring the risk.
The certificate of insurance shall remain in effect at all times throughout
the life of the lease. A new certificate of insurance meeting the above
requirements may be substituted by the Lessee with the State's approval.

Section 25. Assignment of Lease; Successors in Interest.

(a) This lease shall not be assigned in whole or in part without the
written consent thereto of Lessor, who shall not unreasonably withhold such
consent. Provided, however, that if Lessee shall request, by registered mail
addressed to both the Secretary of the Department of Administration and the
Secretary of the Department of Natural Resources and Community Development,
approval of an assignment of the whole or any part of the acreage covered
hereby, and Lessor does not object within ninety (90) days after receipt of
such request, then such request shall be deemed approved by Lessor. Any
request for consent to or approval.of assignment shall contain the full name
and address of the Assignee, a description of the lease portion(s) to be
assigned, and any other information as may reasonably be requested by Lessor.
With the approval of Lessor, either affirmatively or by non-action, this lease
may be assigned in whole or in part.

F-41

(b) The provisions of this agreement shall be binding upon and inure to
the benefit of the heirs, devisees, successors and assigns of the parties
hereto.

[Comment]

Some sort of assignment provision is basic-to any lease. This clause is

modeled on the existing North Carolina clause, with a few additions. The

first is that the lessor will not unreasonably withhold consent; this addition

is necessary to prevent arbitrary or unfair action on the part of the lessor.

The second addition is that the lessor be notified who the assignee is; this

is merely common sense. Also, the lessor's decision on whether to consent to

the assignment may depend on whether the lessor can expect the assignee to

comply with the provisions of the lease. Finally, the clause making the lease

binding on successors or assignees is included here; alternatively, this may

be included as a separate section as is currently the case.

Since assignments are often made in return for a royalty interest (see,,

for instance, the history of North Carolina lease transactions in Figure 2-3),

it is conceivable that, like the lessor's royaltyinterest, these overriding

royalties could cause the assignee to choose not to develop a marginal

property or to abandon it early (see Section 6F, above). Since it is in the

assignor's interest to voluntarily reduce the royalty in such circumstances,

the problem could be left to negotiation between the assignor(s) and the

assignee. Alternatively, the state could include a lease provision here or in

the Reduction of Royalty section stating that any reduction in royalty by the

state for purposes of extending the economic life of the lease will apply

proportionally to overriding royalties as well, and that clauses recognizing

this authority must be included in any lease assignment.

F-42

Section 26. Surrender of Lease.

Lessee may at any time surrender this entire lease or any officially
designated subdivision of the leased area by filing with the,Department a
written relinquishment, which shall be effective as of the date of filing. No
surrender of the lease or of any portion of the leased area shall relieve
Lessee or his surety of the obligation to make payment of all accrued rentals
and royalties or to abandon all wells on the area to be surrendered in a
manner satisfactory to the Department and in compliance with the applicable
rules and regulations issued by the Department. After that, Lessee shall be
released from all obligations under this lease with respect to the surrendered
lands.

Section 27: Notice.

Any notices required or permitted under this lease shall be given by
electronic media producing a permanent record or in writing and shall be
delivered personally or by registered mail. Unless otherwise specified in
this lease, notices from Lessee to Lessor shall be delivered to both the
Secretary of the Department of Natural Resources and Community Development and
to the Secretary of the Department-of Administration of the State of North
Carolina, at [address] , and notices from
Lessor to Lessee shall be delivered to Lessee's executive offices at
[address] - until otherwise designated by
either party to the other. If any party to this lease changes its address
from the one shown herein, that party shall notify the other of such change
within thirty (30) days of such move by the means described above. Any notice
given under this section shall be effective when delivered to the designated
parties.

Section 28. Default; Cancellation.

It is understood and agreed by the parties hereto that if there is any
default or violation on the part of Lessee of any stipulation, agreement,
covenant, or term of this agreement, or if Lessee fails to comply with any of
the provisions of this lease, all work so violating this lease shall cease
immediately whether the violation occurs during the primary term or under any
extension then in effect, and Lessee shall institute such measures as neces-
sary to abate such default or violation; then, if Lessee fails to correct said
defaults or violations within thirty (30) days after notice from Lessor of the
violation or default, it shall be lawful for Lessor to cancel this agreement
and re-enter the premises hereby leased, to repossess and take possession of
the same* and to use, enjoy or re-lease the same as if this lease had not been
entered into. In the event correction by Lessee requires changes to the
plant, equipment, or operations of Lessee, Lessee shall have a reasonable time
necessary to make such changes after notice of violation or default before
Lessor can exercise its right to cancel. Failure by Lessor to enforce this
right or any other granted under this lease in any particular instance shall
not constitute a waiver by Lessor of that or any other provision.

F743

Provided, however, in the event Lessee, upon receiving notice of
violations or default from Lessor, notifies Lessor within fifteen (15) days
after receipt of such notice that it desires to arbitrate the issue of
violation or default, arbitration shall proceed in the manner described in
Section 31 below. It shall be lawful for Lessor to cancel this agreement if
Lessee fails to correct said violations within thirty (30) days after the
arbitration award or, in the event changes are ordered in the plant, equipment
or operations of Lessee, within a reasonable time necessary to make such
changes, which time shall be specified in the arbitration award.

It is specifically provided, however, that the provisions of this section
shall not apply to any violation of the laws of North Carolina, or its
subdivisions, or the United States, or to any rules or regulations adopted
pursuant thereto, and that any violations thereof shall be governed by the
provisions of or procedures set forth therein.

[Comment]

The existing North Carolina default clause has been modified slightly to

produce this section. The clause dealing with failure to enforce the State's

right to cancel was added, and the remainder was reworded. Most leases have a

provision with a similar effect, but many are worded differently from this

one, listing all the possibilities for default and not elaborating on proce-

dures for cancellation or forfeiture. The provision above is more desirable,

then, because it covers default in general and provides for a fair method of

cancellation by the lessor.

It would also be useful to include a provision allowing the state to

cancel the lease, with compensation, should it become evident that further

development on the lease is not in the state's best interests. The following

is a slightly modified version of a provision in the Alaska lease, which

itself was adapted from Section 5 of the U.S. Outer Continental Shelf Lands

Act:

The State may cancel this lease at any time if the State determines,
after Lessee has been given notice and a reasonable opportunity to be heard,
that (1) continued operations pursuant to this lease probably will cause
serious harm or damage to biological resources, to property, to mineral
resources, or to the marine, coastal, or human environment, (2) the threat of
harm or damage will not disappear or decrease to an acceptable extent within a

F-44

reasonable period of time, and (3) the advantages of cancellation outweigh the
advantages of continuing this lease in effect. Any cancellation under this
subsection shall not occur unless and until operations under this lease have
been under suspension or temporary prohibition by the State, with due exten-
sion of the term of this lease, continuously for a period of years
or for a lesser period upon request of Lessee. Any cancellation under this
subparagraph will entitle Lessee to receive compensation as Lessee demon-
strates to the State is equal to the lesser of (1) the value of the cancelled
rights as of the date of cancellation, with due consideration being given to
both anticipated revenues from this lease and anticipated costs, including
costs of compliance with all applicable regulations and stipulations,
liability for clean-up costs or damages, or both, in the case of an oil spill,
and all other costs reasonably anticipated under this lease, or (2) the
excess, if any, over Lessee's revenues from this lease (plus interest on the
excess from the date of receipt to date of reimbursement) of all consideration
paid for this lease and all direct expenditures made by Lessee after the
effective date of this lease and in connection with exploration or develop-
ment, or both pursuant to this lease, plus interest on that consideration and
those expenditures from the date of payment to the date of reimbursement.
Cancellation under this (sub)section may also be submitted into arbitration as
provided for below.

[Comment]

The problem of permits issued or overseen by independent commissions was

discussed in Chapter 5. To allow the state to cancel the lease, with compen-

sation, should a permit from one of these commissions be denied, the above

provision could be used or an additional, more explicit provision could be

included, along the following lines:

The State, at the request of the Lessee, may cancel this lease if (1) a
permit necessary to develop this lease has been denied or has been granted
under conditions that are economically or practically impossible to comply
with, (2) Lessee was not substantially forewarned of such impediments to
develop in the formal notice of sale, and (3) Lessee has exhausted all other
avenues for resolution of the impasse. If the State denies the Lessee's
request for cancellation with compensation under this provision, Lessee may
submit its claim to arbitration as provided for below. During the period
between submission of Lessee's request and its final settlement, all opera-
tions under the Lease shall be suspended, with due extension of the lease
term. If the lease is cancelled by the state under this provision, Lessee
shall be entitled to compensation in accordance with Section above.

F-45

Section 29: Sales Contracts and Exchange Agreements.

Lessee shall submit to the State for approval all contracts and other
agreements for the sale, exchange, or other disposition of oil, gas, natural
gasoline, and other substances produced from the leased lands. Lessee shall
not sell or otherwise dispose of the lease production except in accordance
with sales contracts or other methods first approved in writing by the State.

[Comment]

This section, taken from California's lease, is optional and does not

appear frequently in oil and gas leases. If the State feels the need to have

some control over who the lessee is doing business with and how, either this

sort of provision or one establishing minimum standards for the lessee's

contracts would be useful.

Section 30: Conflicts and Ambiguities.

No express obligation imposed upon Lessee shall relieve it of its exist-
ing duty to exercise due diligence in exploration, development, operation,
marketing or protection activities except to the extent of direct conflict
with such express obligation, and all such express obligations shall be
construed as providing minimal standards only. In case of ambiguity, this
lease always shall be construed in favor of Lessor and against Lessee. Not-
withstanding any of the provisions, covenants or stipulations contained in
this lease, should there be any conflict in any of the provisions of this
lease with the law governing the issuance and operation of leases on the area
herein described, the provisions of such law shall be deemed written into this
lease and shall control.

Section 31: Arbitration.

In the event any dispute is required to be submitted for arbitration by
the terms of Section 28 of this agreement, arbitration shall proceed in the
following manner:

(a) Each party shall select an arbitrator within five (5) days after
Lessee gives notice of its desire to arbitrate.

(b) The arbitrators selected by the parties shall select a third
arbitrator as chairman of the arbitration panel within ten (10)
days after this arbitration provision comes into effect.

(c) The arbitration board shall meet and decide the dispute submitted
to it within fifteen (15) days after the appointment of the
independent arbitrator.

F-46

(d) The decision of the board of arbitrators shall be binding on the
parties provided such decision is not contrary to existing State or
Federal laws, rules and regulations.

(e) The costs of the arbitrators appointed by the parties shall be
borne by the party making the appointment. The expense of the
independent arbitrator and any other expenses incident to the
arbitration proceedings shall be borne equally by the parties.

Section 32: First Lien.

The State of North Carolina shall have a first lien upon all production
from the leased area to secure payment of all unpaid royalty and other sums of
money that may become due under this lease.

Section 33: No Warranty of Titles.

It is specifically understood that Lessor does not warrant that it holds
absolute fee simple title to any of the land described in this lease and that
nothing in this lease may be construed to compel Lessor to establish good
title or defend its title to all or any part of the leased premises. It is
understood that Lessee shall have no recourse whatsoever against Lessor for
failure of Lessor's title, it being expressly agreed that Lessor shall not be
required to return any payments received hereunder or be otherwise responsible
to Lessee therefore.

Section 34: Definitions.

All words and phrases used in this lease are to be interpreted as they
are ordinarily used, except where applicable laws, regulations, or orders
define them otherwise, or their ordinary definition differs from the one
listed below. The following words have the following meanings unless the
context unavoidably requires otherwise:

(1) "Oil" means crude petroleum oil and other hydrocarbons, regardless
of gravity, that are produced in-liquid form by ordinary production
methods, including liquid hydrocarbons known as distillate or
condensate recovered by separation from gas other than at a gas
processing plant.

(2) "Gas" means all natural gas (except helium gas) and all other
hydrocarbons produced that are not defined in this lease as oil.

(3) "Drilling Operations" means the act of boring a hole to reach a
proposed bottom hole location through which oil or gas may be
produced if encountered in paying quantities, and includes
redrilling, sidetracking, deepening, or other means necessary to
reach the proposed bottom hole location, testing, logging,
plugging, and other operations necessary and incidental to the
actual boring of a hole and drawing a product from it.

F-47

(4) "Paying quantities" means quantities sufficient to yield a return
in excess of operating costs, even though drilling and equipment
costs may never be repaid and the undertaking considered as a whole
may ultimately result in a loss.

[Comment]

The value of a Definitions Section is to locate in one place all the

definitions which may cause confusion. It also serves to prevent the clut-

tering of the lease provisions themselves with the technical meanings of the

terms used. Care should be taken in wording these definitions so that the

words have their exact intended meanings and are consistent with other parts

of the lease. The above definitions were taken with minor modifications from

Alaska's lease.

"Market price" definitions vary from lease to lease and can be quite

detailed and lengthy. The following example comes from the U.S. OCS lease:

The value of production for purposes of computing royalty on production
from this lease shall never be less than the fair market value of the
production. The value of production shall be the estimated reasonable value
of the production as determined by the Lessor, due consideration being given
to the highest price paid for a part or for a majority of production of like
quality in the same field or area, to the price received by the Lessee, to
posted prices, to regulated prices, and to other relevant matters. Except
when the Lessor,, in its discretion, determines not to consider special pricing
relief from otherwise applicable Federal regulatory requirements the value of
production for the purposes of computing royalty shall not be deemed to be
less than the gross proceeds accruing to the Lessee from the sale thereof. In
the absence of good reason to the contrary, value computed on the basis of the
highest price paid or offered at the time of production in a fair and open
market for the major portion of like-quality products produced and sold from
the field or area where the leased area is situated, will be considered to be
a reasonable value.

Section 35: Additional or Special Provisions.

[Comment]

Additional provisions might be used to promote various public policy

objectives which may or may not be statutorily required. For example, the

F-48

United States includes provisions regarding equal opportunity, nonsegregated

facilities, and a requirement that twenty percent of the production be offered

to small or independent refineries.

F-49

CEIP PUBLICATIONS

1. Hauser, E. W., P. D. Cribbins, P. T. Tschetter, and R. D. Latta. Coastal
Energy Transportation Needs to Support Major Energy Projects in North
Carolina's Coastal Zone. CEIP Report #1. September 1981. $10.

2. P. D. Cribbins. A Study of OCS Onshore Support Bases and Coal Export
Terminals. CEIP Report #2. September 1981. $10. (NTIS # PB82-202912)

3. Tschetter, P. T., M. Fisch, and R. D. Latta. An Assessment of Potential
Impacts of Energy-Related Transportation Developments on North Carolina's
Coastal Zone. CEIP Report #3. July 1981. $10. (NTIS # PB83-203042)

4. Cribbins, P. S. An Analysis of State and Federal Policies Affecting Major
Energy Priojects in North Carolina's Coastal Zone. CEIP Report #4.
September 1981. $10. (NTIS # PB82-202920)

5. Brower, David, W. D. McElyea, D. R. Godschalk, and N. D. Lofaro. Outer
Continental Shelf Development and the North Carolina Coast: A Guide for
Local Planners. CEIP Report #5. August 1981. $10. (NTIS # PB82-196304)

6. Rogers, Golden and Halpern, Inc. , and Engineers for Energy and the
Environment, Inc. Mitigating the Impacts of,Energy Facilities: A Local
Air Quality Program for the Wilmington, N. C. Area. CEIP Report #6.
September 1981. $10. (NTIS # PB82-197872)

7. Richardson, C. J. (editor). Pocosin Wetlands: an Integrated Analysis of
Coastal Plain Freshwater Bogs in North Carolina. Stroudsburg (Pa):
Hutchinson Ross. 1981. 364 pp. $25. Available from School of Forestry,
Duke University, Durham, N. C. 27709. (This proceedings volume is for a
conference partially funded by N. C. CEIP.)

8. McDonald, C. B. and A. N. Ash. Natural Areas Inventory of Tyrrell County,
North Carolina. CEIP Report #8. dctober 1981. $10. (NTIS # PB83-209072)

9. Fussell, J. 0. t III, and E. J. Wilson. Natural Areas Inventory of Carteret
County, North Carolina. CEIP Report #9. June 1983. $10.

10. Nyfong, T. D. Natural Areas Inventory of Brunswick County, North Carolina.
CEIP Report #10. October 1981. $10. (NTIS # PB83-234039)

11. Leonard, S. W., and R. J. Davis. Natural Areas Inventory for Pender
County, North Carolina. CEIP Report #11. October 1981. $10. (NTTS
PB83-209106)

12. Cribbins, Paul D., and R. Daniel Latta. Coastal Energy Transportation
Study: Alternative Technologies for Transporting and Handling Export
Coal. CEIP Report #12. January 1982. $10. (NTIS # PB83-203067)

13. Creveling, Kenneth. Beach Communities and Oil Spills: Environmental and
Economic Consequences for Brunswick County, N. C. CEIP Report #t3. May
1982. $10. (NTIS # PB83-209064)

14. Rogers, Golden and Halpern, Inc., and Engineers for Energy and the
Environment. The Design of a Planning Program to Help Mitigate Energy
Facility-Related Air Quality Impacts in the Washington County North
Carolina Area. CEIP Report 14. September 1982. $10. (NTIS # PB83-
234021)

15. McDonald C. B., A. N. Ash, and John Fussell. Natural Areas Inventory of
Craven County, North Carolina. CEIP Report #15. December 1981. $10.
(NTIS # PB83-234021)

16. Frost, Cecil C. Natural Areas Inventory of Gates County, North Carolina.
CEIP Report #16. April 1982. $10. (NTIS # PB83-209098)

17. Stone, John R., Michael T. Stanley, and Paul I. Tschetter. Coastal rnergy
Transportation Study: Impacts of Increased Rail Traffic on Communities in
Eastern North Carolina. CEIP Report # 17. August 1982. $10. (NTIS
PB83-203075)

18. Kazarian, Jacqueline S. Newport River Estuary Dye Study: An Analysis of
Water Movement. CEIP Report 18. March 1983. $10.00.

3/84

CEIP PUBLICATIONS

19. Pate, Preston P. , and Robert Jones. Effects of 11pland Drainage on
Estuarine Nursery Areas of Pamlico Sound, North Carolina. CFlP Report #19.
December 1981. $1.00. (UNC Sea Grant Working Paper 81-10). (NTIS # PB83-
168096)

20. Carraway, R. J., and L. J. Priddy. Mapping of Submerged Grass Beds in Core
and Bogue Sounds, Carteret County, North Carolina, by ConvenLional Aerial
Photography. CEIP Report #20. November 1983. $10.

22. Gregory, J. D. , R. W. Skaggs, R. G. Broadhead, R. 11. CulbreaLh, J. R.
Bailey, and T. Foutz. Hydrologic and Water Qua] ity Imp6cts of Peat Mining
in the Coastal Zone of North Carolina. CEIP Report #22. Jointly ptiblished
as N.C. Water Resources Research Institute Report #214. September 1983.
$8 (available from WRRI).

24. Stoll, Evans, Woods So Associates. Railroad Induced Vibration%, New Bern,
North Carolina, August 10 & 11, 1983. CEIP Report #24. March 1983. $1 .00.
(NTIS # PB83-233221)

25. Wang Engineering Co., Inc. Analysis of the Impact of Coal Traing M(,ving
Through Morehead City, North Carolina. CEIP Report #25. October lc)82.
$10. (NTIS # PB83-200865)

26. Anderson & Associates, Inc. Coal Train Movements Through the CiLy of
Wilmington, North Carolina. CEIP Report #26. October 1982. $10. (N,rys
PB83-200857)

27. Peacock, S. Lance and J. Merrill Lynch. NattiraL Areas Inventory of
Mainland Dare County, North Carolina. CEIP Report #27. November 1982.
$10. (NTIS # PB83-208736)

28. Lynch, J. Merrill and S. Lance Peacock. Natural. Areas Inventory of Hyde
County, North Carolina. CEIP Report #28. October 1982. $10.
(NTIS # PB83-208728)

29. Peacock, S. Lance and J. Merrill Lynch. Natural Areas Inventory of Pamlico
County, North Carolina. CEIP Report #29. November 1982. $10. (NTTS
PB83-209114)

30. Lynch, J. Merrill and S. Lance Peacock. Natural Areas Inventory of
Washington County, North Carolina. CEIP Report #30. October 1982. $10.
(NTIS # PB83-209080)

31. Mugs, Bruce J. Review and Evaluation of Oil Spill Models for Application
to North Carolina Waters. CEIP Report #31. August 1982. $10. (NTIS
PB83-209056)

32. Lukin, C. G., and L. L. Mauger. Environmental' Geologic Atlas of Lhe North
Carolina Coastal Zone: Dare, Hyde, Tyrrell, and Washington Counties. CEIP
Report #32. November 1983. $10.

33. Sorrell, F. Yates and Richard R. Johnson. Oil and Gas Pipelines in Coastal
North Carolina: Impacts and Routing Considerations. CEIP Report #33.
December 1982. $10. (NTIS # PB83-233973)

34. Roberts and Eichler Associates, Inc. Area Development Plan for Radio
Island. CEIP Report #34. June 1982. $10. (NTIS # PB83-200873)

35. Cribbins, Paul D. Coastal Energy Transportation Study: The Potential for
Wide-Beam, Shallow-Draft Ships to Serve Coal and Other Bulk Commodity
Terminals along the Cape Fear River. CEIP,Repoit #35. August 1982. $10.
(NTIS # PB83-203380)

36. DNRCD Peat Mining Task Force. Peat Mining and Natural Resources. CEIP
Report #36. March 1983. $10. (NTIS # PB83-172049)

37. Vandenberg, J. J. , and K. R. Knoerr. The Deposit of Airborne Materials in
the Lake Phelps, N.C. , Region. CEIP Report 1137. March 1983. $10. (NTIS
PB83-234054)

38. Wyman, C. D. , D. J. Brower, and R. M. Kessler. Oil and Ga s Leasing of North
Carolina's Submerged Lands. CEIP Report #38. March 1984. $10.

3/84

DATE DUE

GAYLORD No. 2333 PRINTEDINU.S.A.

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