[House Hearing, 107 Congress]
[From the U.S. Government Publishing Office]
MAXIMIZING POWER GENERATION AT FEDERAL FACILITIES
=======================================================================
OVERSIGHT HEARING
before the
SUBCOMMITTEE ON WATER AND POWER
of the
COMMITTEE ON RESOURCES
U.S. HOUSE OF REPRESENTATIVES
ONE HUNDRED SEVENTH CONGRESS
FIRST SESSION
__________
April 26, 2001
__________
Serial No. 107-22
__________
Printed for the use of the Committee on Resources
Available via the World Wide Web: http://www.access.gpo.gov/congress/
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COMMITTEE ON RESOURCES
JAMES V. HANSEN, Utah, Chairman
NICK J. RAHALL II, West Virginia, Ranking Democrat Member
Don Young, Alaska, George Miller, California
Vice Chairman Edward J. Markey, Massachusetts
W.J. ``Billy'' Tauzin, Louisiana Dale E. Kildee, Michigan
Jim Saxton, New Jersey Peter A. DeFazio, Oregon
Elton Gallegly, California Eni F.H. Faleomavaega, American Samoa
John J. Duncan, Jr., Tennessee Neil Abercrombie, Hawaii
Joel Hefley, Colorado Solomon P. Ortiz, Texas
Wayne T. Gilchrest, Maryland Frank Pallone, Jr., New Jersey
Ken Calvert, California Calvin M. Dooley, California
Scott McInnis, Colorado Robert A. Underwood, Guam
Richard W. Pombo, California Adam Smith, Washington
Barbara Cubin, Wyoming Donna M. Christensen, Virgin Islands
George Radanovich, California Ron Kind, Wisconsin
Walter B. Jones, Jr., North Carolina Jay Inslee, Washington
Mac Thornberry, Texas Grace F. Napolitano, California
Chris Cannon, Utah Tom Udall, New Mexico
John E. Peterson, Pennsylvania Mark Udall, Colorado
Bob Schaffer, Colorado Rush D. Holt, New Jersey
Jim Gibbons, Nevada James P. McGovern, Massachusetts
Mark E. Souder, Indiana Anibal Acevedo-Vila, Puerto Rico
Greg Walden, Oregon Hilda L. Solis, California
Michael K. Simpson, Idaho Brad Carson, Oklahoma
Thomas G. Tancredo, Colorado Betty McCollum, Minnesota
J.D. Hayworth, Arizona
C.L. ``Butch'' Otter, Idaho
Tom Osborne, Nebraska
Jeff Flake, Arizona
Dennis R. Rehberg, Montana
Allen D. Freemyer, Chief of Staff
Lisa Pittman, Chief Counsel
Michael S. Twinchek, Chief Clerk
James H. Zoia, Democrat Staff Director
Jeff Petrich, Democrat Chief Counsel
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SUBCOMMITTEE ON WATER AND POWER
KEN CALVERT, California, Chairman
ADAM SMITH, Washington, Ranking Democrat Member
Richard W. Pombo, California George Miller, California
George Radanovich, California, Peter A. DeFazio, Oregon
Vice Chairman Calvin M. Dooley, California
Greg Walden, Oregon Grace F. Napolitano, California
Michael K. Simpson, Idaho James P. McGovern, Massachusetts
J.D. Hayworth, Arizona Hilda L. Solis, California
C.L. ``Butch'' Otter, Idaho Brad Carson, Oklahoma
Tom Osborne, Nebraska
Jeff Flake, Arizona
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C O N T E N T S
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Page
Hearing held on April 26, 2001................................... 1
Statement of Members:
Calvert, Hon. Ken, a Representative in Congress from the
State of California........................................ 1
Prepared statement of.................................... 2
Cannon, Hon. Chris, a Representative in Congress from the
State of Utah.............................................. 16
Prepared statement of.................................... 16
Flake, Hon. Jeff, a Representative in Congress from the State
of Arizona, Prepared statement of.......................... 12
Shadegg, Hon. John B., a Representative in Congress from the
State of Arizona, Prepared statement of.................... 2
Articles submitted for the record........................ 20
Statement of Witnesses:
Erickson, Richard L., Secretary/General Manager, East
Columbia Basin Irrigation District......................... 62
Prepared statement of.................................... 64
Feider, James C., General Manager, Redding Electric Utility
Department, City of Redding, California.................... 50
Prepared statement of.................................... 51
Johnson, Rick, Executive Director for Science, Southwest
Rivers, Grand Canyon Trust, and Grand Canyon River Guides.. 43
Prepared statement of.................................... 45
McDonald, J. William, Acting Commissioner, Bureau of
Reclamation, U.S. Department of the Interior............... 3
Prepared statement of.................................... 5
McInnes, Micheal, Sr., Vice President/Deputy General Manager,
Tri-State Generation and Transmission Association, Inc..... 30
Prepared statement of.................................... 32
Map of Colorado River Basin Power and Water Resources.... 37
Scott, Aleka, Transmission Manager, Pacific Northwest
Generating Cooperative..................................... 52
Prepared statement of.................................... 54
Wegner, David L., Board of Directors, Glen Canyon Institute.. 38
Prepared statement of.................................... 39
MAXIMIZING POWER GENERATION AT FEDERAL FACILITIES
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Thursday, April 26, 2001
U.S. House of Representatives
Subcommittee on Water and Power
Committee on Resources
Washington, DC
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The Subcommittee met, pursuant to call, at 2 p.m., in Room
1324, Longworth House Office Building, Hon. Ken Calvert
[Chairman of the Subcommittee] presiding.
STATEMENT OF THE HONORABLE KEN CALVERT, A REPRESENTATIVE IN
CONGRESS FROM THE STATE OF CALIFORNIA
Mr. Calvert. The oversight hearing by the Subcommittee on
Water and Power will come to order. The Subcommittee is meeting
today to hear testimony on maximizing power generation at
Federal facilities. We will be joined shortly by the Ranking
Member Adam Smith, but in the interest of time, we are going to
move this hearing along. Under committee rule 4(g), the
Chairman and the Ranking Minority Member can make opening
statements. If any other Members have statements, they can be
included in the hearing and the record under unanimous consent.
Over the last century, electricity consumers have invested
hundreds of millions of dollars in Federal hydroelectric
facilities. They have invested in good faith that those
facilities would be maintained and that they would provide
electricity when needed. However, the generating capacity at
many of these facilities have been eroded over time. During the
past 6 years our Subcommittee has asked the General Accounting
Office to examine ways that we can improve the operation of the
Federal hydropower projects.
While we have made progress, the Bureau of Reclamation is
still faced with a $5 billion backlog. Generation at other
projects has been strained due to regulatory restrictions. Glen
Canyon Dam has lost one-third of its peaking capacity, and
electricity generation has decreased 13 percent since 1980 at
the Central Valley Project because of environmental
regulations. Electricity bills are rising as utility companies
are forced to replace this lost power by going into the market
and competing for scarce supplies. These costs will only
increase as hot summer weather escalates demand and drought
decreases supply of both power and water.
Keeping the lights on this summer and in the future means
that we must be careful to maximize the use of our limited
resource. We cannot continue to talk about managing our water
resources or power resources as two separate areas. But it is
easy to see the direct link between water and power at
hydroelectric dams. What is often overlooked is the fact that
conventional generation also uses a large amount of water.
Responsible planning for the future means ensuring adequate and
reliable supplies of both resources.
This hearing is another step in looking at how Federal
water and power resources can be better managed to create
stable supplies and meet future demand. It is good sense and
good policy to maximize benefits from existing facilities to
meet the needs of both power and water users.
[The prepared statement of Mr. Calvert follows:]
Statement of The Honorable Ken Calvert, Chairman, Subcommittee on Water
and Power
Over the last century electricity consumers have invested hundreds
of millions of dollars in federal hydropower facilities. They have
invested in good faith that these facilities would be maintained and
that they would provide electricity when needed.
However, the generating capacity in many of these facilities has
been eroded over time. During the past 6 years, our Subcommittee has
asked the General Accounting Office to examine ways we can improve the
operation of federal hydropower projects. While we have made progress,
the Bureau of Reclamation is still faced with a $5 billion dollar
backlog.
Generation at other projects has been constrained due to regulatory
restrictions. Glen Canyon Dam has lost one-third of its peaking
capacity and electricity generation has decreased 13 percent since 1980
at the Central Valley Project because of environmental regulations.
Electricity bills are rising as utility companies are forced to
replace this lost power by going into the market and competing for
scarce supplies. These costs will only increase as hot summer weather
escalates demand, and drought decreases the supply of both power and
water.
Keeping the lights on this summer, and in the future, means that we
must plan carefully to maximize the use of our limited resources. We
cannot continue to talk about managing our water resources, or our
power resources, as two separate areas. While it is easy to see the
direct link between water and power at hydroelectric dams, what is
often overlooked is the fact that conventional generation also uses a
large amount of water. Responsible planning for the future means
ensuring adequate and reliable supplies of both resources.
This hearing is another step in looking at how federal water and
power resources can be better managed to create stable supplies and
meet future demand. It's good sense and good policy to maximize
benefits from existing facilities to meet the needs of both power and
water users.
I'd like to thank our witnesses and look forward to hearing from
them at this time.
______
[The prepared statement of Mr. Shadegg follows:]
Statement of The Honorable John Shadegg, a Representative in Congress
from the State of Arizona
Mr. Chairman, thank you for the opportunity to take part in today's
hearing. I ask that three newspaper articles be made part of the
record.
On March 21, 2001, Knight Ridder reported on blackouts in
California the day before which lasted four and a half hours before
sufficient power was available to lift the blackout. The paper reports
``Grid officials credited an influx of 300 megawatts from the Glen
Canyon hydroelectric plant'' for ending the blackout.
On December 9, 2000, the Washington Post reported that the
``California power grid is on verge of collapse'' and stated that two
days earlier ``The grid was also saved by a last-minute surge of juice
from the Western Area Power Administration, which sent electricity over
its lines from its facility at the Glen Canyon Dam.''
Finally, on September 25, 2000, the Dow Jones Energy Service ran a
story under the headline ``U.S. Dam Rescues California Grid'' and wrote
``California averted a blackout last week with some help from the
federal government. The U.S. Bureau of Reclamation opened the
floodgates at the massive Glen Canyon dam in Arizona providing 300
megawatts of power.''
The article also points out that ``Under a mandate from the
Interior Department to restore riverbank beaches ... Glen Canyon has
been operated for the last few years in a way that reduces net power
production from the dam by about 900 megawatts.''
We have three examples in less than a year of how vital Glen Canyon
Dam, and the peaking power it provides, are to the safety of the
Western electricity grid and thus to the well-being and lives of the
people who depend on that grid. Yet there are some individuals who want
to tear down the dam and thus deprive people of this power, as well as
the water which the dam stores as insurance against a long term
drought.
The current electricity crisis stems from a lack of generation
capacity, a fact attested to by numerous power experts including the
three Commissioners of the Federal Energy Regulatory Commission. This
crisis is exacerbated by operating restrictions imposed by the 1996
Record of Decision which prevent Glen Canyon Dam from producing at full
capacity unless blackouts are imminent.
Glen Canyon Dam is a major generating asset which, if used
efficiently, could provide significantly more power to Arizona and
other basin states, and thus make more power available to address
shortages throughout the West. By preventing it from being used in this
way, the operating restrictions imposed by the 1996 Record of Decision
are implementing a decision that beaches along the Colorado River are
more important than the well-being of people.
______
Mr. Calvert. I would like to thank our witnesses for coming
out here today and look forward to hearing from them. When Mr.
Smith arrives, we will give him time for his opening statement.
In the meantime, we will go ahead and introduce our first
panel, which is Mr. J. William McDonald, the Acting
Commissioner, Bureau of Reclamation, and he is accompanied by
Mr. Mike Hacskaylo, Administrator of the Western Area Power
Administration; and Mr. Jeff Stier, Vice President for National
Relations, Bonneville Power Administration.
And with that, Mr. Bonneville--or excuse me, Mr.
Bonneville, yeah, I will get that--if there is such a person,
please raise your hand. I will now recognize Mr. McDonald to
testify for 5 minutes. You have some timing lights there. We
would appreciate that you would attempt to stay within that 5
minutes so that we have plenty of time to ask some questions.
With that, will Mr. McDonald please begin your testimony?
STATEMENT OF J. WILLIAM McDONALD, ACTING COMMISSIONER, BUREAU
OF RECLAMATION, ACCOMPANIED BY MIKE HACSKAYLO, ADMINISTRATOR OF
WESTERN AREA POWER ADMINISTRATION; AND JEFF STIER, VICE
PRESIDENT FOR NATIONAL RELATIONS, BONNEVILLE POWER
ADMINISTRATION
Mr. McDonald. Thank you, Mr. Chairman. I have a written
statement, and I will simply summarize that, if I may, please.
The Bureau of Reclamation, as you well know, is the second
largest hydropower utility in the United States with 194
generating units located in 58 power plants throughout the
Western States. We have an installed capacity of about 14,700
megawatts, which produce power for our project use and our
customers. We are the mainstay, in many ways for ensuring the
reliability of the Western Interconnected System.
There are several general conditions under which our power
plants and out power system operates. I would like to touch on
those by way of a general summary. First, water is the fuel of
the hydropower system, and while it has the advantage of being
an annually renewable fuel, it is finite, and it varies
substantially from year to year.
Secondly, even if water is in storage in one of our project
reservoirs, the annual amount of water available for release is
always governed by a variety of laws, and generally speaking
those would be international treaties, interstate compacts and
judicial decrees apportioning interstate streams, and then a
variety of Federal project-authorizing statutes which govern
project operations.
Thirdly, the scheduling on a daily and a weekly basis of
water is governed by water user demands, water supply being the
primary authorized project purpose in all cases, and hydropower
production at our projects being a secondary congressionally
authorized project purpose.
Fourthly, power generated by our facilities is used first
for project purposes, for example, project pumping to lift
irrigation supplies to our irrigators. On an agency-wide
average annual basis, we use about 5 to 7 percent of the energy
which is generated every year. The balance, which we refer to
as surplus power, is marketed by the Western Area Power
Administration or the Bonneville Power Administration. They do
all marketing, all contracting and make the necessary purchases
of replacement power. How and to whom power is marketed is done
in accordance with Federal law, and to make very complex
storage simple, in general that marketing is to so-called
preference customers.
And finally, let me emphasize that throughout Reclamation,
all firm power via Western and Bonneville, is under contract.
Sixthly, it is important to understand that there are some
significant transmission constraints in the Western grid
system. Those are schematically shown on a map attached to my
statement. I would just emphasize that even if Reclamation can
generate it, we cannot necessarily get it to the right place.
And finally, there are contemporary environmental and
tribal trust asset considerations that affect project
operations. They particularly relate to downstream riverine
environments and aquatic species, and particularly reflect
themselves relative to the use of our plants for peaking
purposes; that is to say they can affect energy, although
typically not capacity.
About 85 percent of our total capacity is concentrated in
four systems. Let me just touch very briefly on those,
particularly related to the California power situation. The
Central Valley Project in California consists of six power
plants. About 75 percent of the energy generated by that system
is surplus to project needs. All of that is under contract by
Western to users in California. This year, our forecasted
runoff in the Central Valley is only about 60 percent of
average. As a consequence, power generation, coupled runoff
with reservoir releases, will only be about 80 percent of
average this summer.
We are doing three main things with the Central Valley
Project to try to help the California situation. First, all
maintenance that we would--would routinely do in the winter
will be completed by June 1st. Secondly, we are shifting
project pumping to off-peak hours as much as we can. And
thirdly, we are doing everything we can to optimize and
schedule releases for peak demand periods within the limits of
delivery in our water supply.
The second major system are the dams on the lower Colorado
River, Hoover, Parker and Davis, which straddle the Colorado
River on the California/Arizona border. Annual releases there
are governed by the complex body of laws known as the Law of
the Colorado River, which includes a treaty, compact, U.S.
Supreme Court decrees, statutes and contracts.
I think what I would emphasize here is two things. All
power marketed from the lower Colorado River is, by statute,
provided 50 percent to California entities. All of that is
under contract, and we are able to respond on the lower
Colorado River to Stage 3 emergencies declared by California
through the California ISO, and, in fact, have done that on all
occasions that occurred this winter.
The third major piece of the system is the Federal Columbia
River Power System. The thing to emphasize there, by way of
conclusion, is that that is a system that typically is able to
sell power to California in the summer when California has
summer peaks. In turn, historically California has sold power
to the Pacific Northwest in the winter when the Pacific
Northwest has its peaks.
The Columbia River system faces a near record drought this
year, or perhaps a record drought. Under those circumstances,
we will have to run the Federal Columbia River Power System
generating all power for the use of the Bonneville Power
Administration and its customers and in general would not
expect this summer to be able to sell power from the Pacific
Northwest to California.
I would just conclude by observing, Mr. Chairman, that over
the years, particularly in the past 15 to 20 years, we have
been able to uprate and rewind turbines at many of our
facilities such that we have added about 1,800 megawatts. The
future would hold the opportunity for about another 500
megawatts, by doing additional uprates, rewinds and turbine
runner replacements so there is still the opportunity for some
capacity in the system.
With that, I will conclude my remarks and be glad to
respond to questions.
Mr. Calvert. Mr. McDonald, I thank you for your testimony.
[The prepared statement of Mr. McDonald follows:]
Statement of J. William McDonald, Acting Commissioner, Bureau of
Reclamation, U.S. Department of the Interior
I am Bill McDonald, Regional Director for the Bureau of
Reclamation's (Reclamation) Pacific Northwest Region located in Boise,
Idaho, and am currently serving as Acting Commissioner. I appreciate
the opportunity to discuss Reclamation's role in regulating the flow of
water on key rivers and the impact on output of hydroelectric plants
that are operated by Reclamation.
Before I discuss Reclamation's current activities as they relate to
the generation of hydroelectric power, I would like to give the
Subcommittee some background on Reclamation's hydroelectric power
activities. This should provide important context as we discuss the
current situation and Reclamation's role and activities.
Background
The Bureau of Reclamation is the nation's second largest producer
of hydroelectric power. It ranks as the 10th largest power producer in
the United States with 58 hydroelectric powerplants, 194 generating
units in operation and an installed capacity of 14,744 megawatts (MW).
In addition, Reclamation has a 547 MW share of the installed capacity
of the coal-fired Navajo Steam Powerplant. The power produced at such
projects that is available for commercial sale is marketed by the
Western Area Power Administration (Western) and the Bonneville Power
Administration (Bonneville).
Reclamation powerplants annually generate about 49 billion kilowatt
hours (kWh) of hydroelectric energy--enough to meet the annual
residential needs of over 14 million people or the electrical energy
equivalent of over 80 million barrels of crude oil. Currently
Reclamation's Central Valley Project accounts for about 4 percent of
California's installed capacity in state. Westwide, Reclamation helps
to maintain the stability and reliability of the overall power grid
through the Western Systems Coordinating Council (WSCC) - a voluntary
system reliability organization in which Reclamation, the California
utilities and 13 other western states participate.
Over the past 25 years, Reclamation has done a great deal to
increase the generation capacity of its hydroelectric facilities
throughout the west. In 1976, Reclamation had 50 powerplants with a
total capacity of 9,111 MW. Today, Reclamation's 58 powerplants have an
installed capacity of 14,744 MW for a 62 percent increase. It is
important to note that Reclamation's aggressive uprating and rewind
program at existing power plants accounts for more than 1,783 MW of
that increase, which represents 12 percent of Reclamation's total
generation capacity.
Legal and Operational Issues: While Reclamation's installed
nameplate capacity is significant, there are a number of legal and
operational factors that limit energy generation.
1) Power is Secondary Purpose: Reclamation's hydroelectric power
facilities are part of specifically authorized multipurpose water
projects which provide benefits such as irrigation, municipal and
industrial water supply, flood control, fish and wildlife protection
and recreation. Power is, by statute for most projects, a secondary
project function to delivery of irrigation and municipal and industrial
water supplies. This means that water deliveries, pursuant to
contracts, take precedence over electric power generation. Further,
many projects are required to schedule water deliveries in accordance
with interstate apportionment decrees and compacts and with
international treaties. Therefore, water may not be available to
generate power, as it may be committed to a primary project function
such as flood control, or agricultural or municipal and industrial
deliveries. In some cases, Reclamation may be required to release more
water from its reservoirs than can be accommodated using only the power
plant turbines.
2) Only Surplus Power is Marketed: Under Reclamation law, the first
priority for the use of power generated by Reclamation's projects is to
meet the needs of that project. This includes power for pumping water
for delivery to our water users. On a Reclamation-wide basis, about 5
to 7 percent of the power we generate each year is used for project
purposes. Within parts of the Central Valley Project (CVP) in
California, however, there are times of the year--particularly during
the irrigation season--when our generation does not even produce enough
power to meet the project's pumping needs. In response, Western must
buy power to serve irrigation needs on the spot market just like any
other power user.
When there is power surplus to a project's needs, it is provided to
Western or to Bonneville in the Pacific Northwest. Reclamation manages
only the generation of power at its facilities. These Federal agencies
in turn market this power to customers who are primarily preference
customers, such as municipal utilities, as required by statute.
Portions of the revenues derived from such sales are used to repay
their investment costs that are the responsibility of the irrigators
but exceed their ability to repay.
3) Power is Already Committed by Contract: As the marketers for
Reclamation's power, Bonneville and Western have entered into contracts
with preference customers for all of the anticipated available
generation. The only time that additional power may be available to
non-contracted entities is when there is excess water in the system
that can produce more power than is already obligated or expected. All
power generated at Hoover Dam is committed even when there is excess
water in the system. In a dry year, however, Western and Bonneville
have to buy power from other sources to make up the difference in their
existing contracts. In today's spot markets, those costs have increased
as much as ten fold over the last year. In a normal or dry year, there
is little or no power produced that is not already under contract
through Western or Bonneville.
4) Transmission System Constraints: Map 1 attached to my testimony,
shows a multitude of power facilities - albeit small ones - on the east
side of the Continental divide. These facilities currently serve
customers in the regions in which they are located. Map 2 shows that
the Federal transmission system is not designed to move power from
these units long distance to California. Also, within California, the
capacity to move electricity, particularly from the south to the north,
is limited. Thus, although Reclamation through Western, delivers power
from Hoover, Parker and Davis Dams on the Lower Colorado River to Los
Angeles and Southern California, there is at times insufficient
transmission capacity to get that power to northern California - where
much of the recent need has been.
There is also no Federal transmission line to get electricity from
Glen Canyon Dam, on the Colorado River, to either southern or northern
California. Power from Glen Canyon Dam can be sent to Arizona, but
there is usually insufficient transmission capacity to get electricity
through Arizona to California. To do so would displace other power that
is also intended for California, unless Western is able to exchange
power with some other entity.
5) Hydrologic Conditions: Water is the fuel for a hydropower
system. While water is an annually renewable fuel, its availability
varies considerably from year to year.
In California, water supply forecast is now about 40 percent below
normal. As a result, Reclamation's hydro generation is below average.
Reclamation's CVP power facilities, in an average summer, generates
5,000 gigawatt hours(GWh). This summer, however, due to low river and
reservoir levels, CVP facilities are expected to generated only about
4,100 GWh--which is 18% below average.
In the Pacific Northwest, the runoff forecast is for a near record
drought. While the average annual flow of the Columbia River at the
Dalles is about 106 million acre feet, flows this year will be only
half that amount.
6) California/Northwest Exchange: Historically, the Pacific
Northwest and California have exchanged power during their respective
high demand seasons--winter in the Pacific Northwest and summer in
California. In the summer, when the Northwest's demand is lower, the
Pacific Northwest exports power to California--during its high demand
season. Then, in winter, when California's demand is--on average--
lower, California exports power to the northwest - where the winter
months are colder and demand is higher. This relationship has served
both regions well.
Unfortunately, it is not working that way this year. As we saw this
past winter, California was not able to export power to the north, as
they were not able to meet their own winter needs. In fact, California
found itself in need of imported power (at a time when they usually
export it). This meant that Bonneville, which usually depends upon
California's imports, did not have imported power available to meet its
customers' load. In response, Bonneville needed to increase the output
of the facilities of the Federal Columbia River Power System (FCRPS),
as well as buy power on the spot market. It also meant that there was
significant draw down of the reservoirs in the FCRPS. This year, with
the dry weather, there is little prospect that these reservoirs will be
able to refill this summer. To California, this means that the Pacific
Northwest may not be able to export power during the upcoming summer
months. Bonneville will continue to exchange energy whenever possible
to help California with peaking problems while providing the Northwest
with much needed energy.
7) Environmental and Trustee Considerations: Reclamation must also
operate its projects consistent with environmental laws, such as the
Endangered Species Act, and with Indian trust property responsibilities
and Indian fishing rights. In any hydropower system there can be
significant fluctuations in flow that may have impacts on the
environment and recreation. Since most Reclamation hydropower
facilities are located on rivers inhabited by threatened and endangered
fish species, operations are constrained to ensure that these fish and
their habitat are not jeopardized by adverse flow schedules or pulsed
flows. We are coordinating with National Marine Fisheries Service and
the U.S. Fish and Wildlife Service to identify opportunities to provide
additional assistance for power generation that will not adversely
affect these fishery resources.
System Reliability: Mr. Chairman, one of the significant benefits
of hydropower, in general, and Reclamation's system, in particular, is
the flexibility it affords. Hydro generation can be ramped up or down
very quickly to respond to changes in demand and to the needs of the
regional transmission system to remain stable. (A caveat here is that
rapid changes may have detrimental fish and wildlife impacts.) Because
of the size of Reclamation's system, along with its capacity and the
large number and diversity of units available, Reclamation serves as a
mainstay for ensuring the reliability of the Western Interconnected
System. In the event of a WSCC system emergency, Reclamation hydro
power can be brought on-line quickly to meet system emergency demands.
Reclamation hydro power also provides voltage control, load following,
spinning reserves, and black start capability'' all of which provide
critical, much-needed stability to the western power grid.
Current Activities in Response to Power Crisis: Reclamation works
closely with Bonneville, Western, the WSCC and the California
Independent System Operator (ISO) to provide whatever assistance it can
to California.
1) Adjustments to Increase ``Peaking Power'': Reclamation continues
to work on flexible power generation schedules to support the needs of
the western power grid. Western and Bonneville, on behalf of the
California ISO, routinely ask Reclamation to rearrange its power
generation schedule to help with the morning and afternoon peaks. In
many cases, Reclamation has asked its project pumping customers to
shift the timing of their deliveries to off-peak times to make more
peaking power available to the market. At Grand Coulee Dam in eastern
Washington, we have been able to shift more than 300 megawatts of
pumping load to off peak times--making it available to Bonneville for
peaking purposes. This summer in the CVP, Reclamation anticipates that
significant project pumping loads can be shifted to off-peaking, making
that power available to Western to help meet the demand for peaking
power in California.
2) Conservation: Reclamation continues to maximize power production
and minimize consumption to reduce projects needs and make power
available. We have also facilitated the purchase of water that would
otherwise need to be pumped or diverted upstream of the generators.
This makes both more water available for generation and makes some
``project use power'' available to the market.
3) Maintenance Schedules: In California, Reclamation has complied
with the ``No Touch Day'' requirement and ``Warning'' market notices.
These notices have been in effect for all 105 days of 2001. Generator
maintenance or maintenance of communications or protective systems is
not be performed if a ``No Touch Day'' is in effect. Over the past
year, Reclamation has worked very closely with Bonneville and Western
to coordinate scheduled maintenance activities to maximize the number
of facilities on line to respond to the energy needs of the western
United States. In many instances scheduled maintenance that requires
outages, has been delayed or rescheduled to accommodate system needs.
Where maintenance cannot be delayed, Reclamation has resorted to double
shifting at some facilities, and a greater use of overtime, to shorten
the time that facilities will be out of service.
4) Responses to Stage 3 Emergencies: While Reclamation's ability to
generate power sometimes is limited by the factors identified above, we
have been able to respond to requests from Western and Bonneville on
behalf of the California ISO during many of the recent emergencies to
provide additional power to California. Within the CVP, for example,
Reclamation placed all its CVP generating units into production for the
duration of the emergency. In the Pacific Northwest, Reclamation, in
consultation with Bonneville, reshaped the water releases to assist
California during Stage 3 events. In addition, the following chart
indicates the specific increases from Hoover and Glen Canyon dams as of
April 19, 2001.
Future Activities and Opportunities: As stated above, Reclamation
has over the past 25 years undertaken an aggressive uprating and
efficiency improvement program, which has significantly expanded the
capacity of our hydropower system. While most of the significant
benefits have already been realized, Reclamation has identified and
will continue to explore additional opportunities to further expand our
capacity and efficiency.
1) Increase Efficiency and Reliability: In partnership with
Bonneville, Western and some of our power customers, Reclamation is
working to replace the turbine runner blades in some of our facilities.
The on-going runner replacement work at Grand Coulee, for example, can
increase the efficiency of the facility and will result in 45-50 MW of
additional energy at the facility. Reclamation is exploring the
feasibility of other investments such as a similar effort at Shasta Dam
in California which could result in an additional 51 MW of power. We
estimate that by doing this at other Reclamation facilities,
Reclamation could realize an additional gain of as much as 350 MW over
the next 5 to 10 years.
2) Additional Uprates and Rewinds: While most of the significant
increases in capacity have already been realized by our long standing
uprating and rewind efforts, we can see that over the next 5 to 10
years, an additional 200 MW gain is possible across all of
Reclamation's power system.
3) Increased Focus on Power Facility Reliability - Reclamation
hydropower plants are an average of 44 years old. Given this aging
infrastructure, Reclamation is placing an increasing emphasis on the
reliability of our plants in our operation and maintenance activities.
Additionally, we are exploring the possibility of Reliability Centered
Maintenance and Life Extensions in order to assure continued
reliability of our plants.
Conclusion
In summary, Mr. Chairman, Reclamation's hydropower projects play a
significant role in addressing California's power needs - both in terms
of supply and in terms of maintaining the stability of the system. In
the summer of 2000, and so far in 2001, the below normal water supplies
have limited and will continue to limit our ability to generate
hydropower.
This concludes my testimony. I would be glad to answer any
questions.
______
[Attachments included in Mr. McDonald's testimony follow:]
[GRAPHIC] [TIFF OMITTED] T1928.011
[GRAPHIC] [TIFF OMITTED] T1928.012
[GRAPHIC] [TIFF OMITTED] T1928.013
Mr. Calvert. We have a vote on the floor, followed by one
additional vote, so we will recess and then immediately
reconvene, and Mr. Cannon at that point has an opening
statement he would like to make.
Mr. Flake?
Mr. Flake. If I am unable, Mr. Chairman, to return, may I
ask without objection that my statement be entered as part of
the record?
Mr. Calvert. Without objection, your opening statement will
be entered into the record.
[The prepared statement of Mr. Flake follows:]
Statement of The Honorable Jeff Flake, a Representative in Congress
from the State of Arizona
Water projects such as the Colorado River Storage Project serve
multiple purposes with the benefits going out to a wide range of
people. While water delivery is first and foremost among these
benefits, power generation has become an equally important purpose with
other factors such as recreation and environment following as ancillary
benefits. Much more so than Eastern states, the West is strongly
dependent upon the valuable resources of their water supplies. I am a
strong supporter of preserving the environment under sound management
plans.
Glen Canyon Dam, largest of the Colorado River Storage Projects
consists of eight generators for a total of about 1300 megawatts
equaling more than 70% of total generation of the CRSP.
Glen Canyon's generating capability has been considerably impacted
over a period of time through various laws and regulations that have
served to stifle the output of the operation. A 1996 Environmental
Impact Statement (EIS) statement subsequently reduced the flow of the
operation and resulted in a 1/3 generating capacity loss for the
project. The complete effect on the environment is speculative. An
April 2000 low flow experiment once again impacted the generating
capability of the project. The alleged benefit of that experiment is
also speculative.
These conditions have forced CRSP customers and WAPA to purchase
replacement power elsewhere at additional cost. While Glen Canyon Dam
currently experiences this 1/3 reduction in output, the project's
emergency release program has been invoked on three occasions since
September of 2000 to prevent a grid outage.
Recommendations on flows of federal hydropower operations must be
based on sound science and accurately reflect true economic impacts.
Returning these dams to prior production capacity would not only
decrease the burden of current energy demands but would provide a clean
source of power.
______
Mr. Calvert. We will recess for 15 minutes, 20 minutes and
reconvene.
[Recess.]
Mr. Calvert. Mr. Cannon will be here shortly, but we will
go ahead and begin testimony and allow Mr. Cannon to begin his
opening statement.
Mr. McDonald, has Reclamation been able to adequately keep
up on repairs and maintenance during the energy crisis so that
there will not be the systemwide outages later on? You
mentioned in your testimony you felt that you would have
everything adequately done by June 1st. Is that pretty much the
case, or do you think that there are other problems that may
have to be dealt with this summer?
Mr. McDonald. Yes. We have no particular concerns. A lot of
plants are down in the winter because water deliveries are
relatively low. So it is typical for us to do our routine
maintenance in the winter, but even as we had plants down this
winter for scheduled maintenance, there is not an instance of
which I am aware that we didn't have sufficient capacity, given
the water available, to generate all power that could be
generated. And as we hit peak summer demands, and we will run
more water through the generators this summer, we will have
everything back online.
Mr. Calvert. How much generating capacity is lost at the
reclamation facility due to the environmental regulations? Do
you have any number on that how many megawatts is lost?
Mr. McDonald. On a West-wide basis it, varies from project
to project where we have confronted situations like that, but
clearly the principle issue has been at the Glen Canyon Dam
where there has been about a 30 to 33 percent loss in capacity
relative to historic operations, pursuant to the requirements
of the Glen Canyon Protection Act.
Mr. Calvert. And how much--what is that peak power, and how
do we define that in megawatts of peak power, 35 percent?
Mr. McDonald. Well, the installed capacity at Glen Canyon
is--a couple of experts here help me--I believe it is just
about 2,400 megawatts.
Mr. Calvert. So we are looking at about 700 megawatts of
lost peak power; is that correct?
Mr. McDonald. Yes. Except I think I am getting corrected
here. You are right. Thank you, Mike. I apologize.
At Glen Canyon, the installed capacity is about 1,300
megawatts.
Mr. Calvert. So we are looking at about 400?
Mr. McDonald. About 400 megawatts reduction in capacity.
Mr. Calvert. Mr. McDonald, what types of emergencies will
allow the Bureau to deviate from operational plans to maximize
power generation?
Mr. McDonald. At Glen Canyon Dam, Mr. Chairman?
Mr. Calvert. At Glen Canyon or any other dam.
Mr. McDonald. Again, it is project-specific. In the Record
of Decision that was adopted following the EIS on Glen Canyon
Dam, there are specific emergency exception criteria. At
Trinity reservoir and complex, which is a division of the
Central Valley Project, we are in the process of likewise
developing emergency criteria. We are operating in the Pacific
Northwest right now pursuant to biological opinions just issued
in December, and, again, they provide for deviations from those
requirements if there is a system emergency. And, in fact, we
have declared such an emergency, we being Bonneville Power
Administration and Corps of Engineers and Bureau of Reclamation
in that case, just a few weeks ago and are operating pursuant
to those create.
Mr. Calvert. I guess does that mean this summer if--in the
Western grid if we have significant power outages, will
Reclamation order additional power generation at those
facilities--
Mr. McDonald. We are able to respond principally in three
ways at the Central Valley Project, and, again, within the
limits of scheduling for water deliveries--
Mr. Calvert. How about Glen Canyon?
Mr. McDonald. --we can shape the peaks. We can do the same
thing on the lower Colorado River at Glen Canyon if the
exception criteria are met, number one, and, in the context of
California, I would emphasize if transmission capacity is
available, which is a very major constraint, because Glen
Canyon was never meant to be a provider of electricity to
California, so there is a significant lack of transmission.
Mr. Calvert. Well, it is not just California. I think that
the issue of power generation is not just a California issue. I
suspect it is more of a Western grid issue. So if, in fact,
there is a problem in the West--I don't want to define it just
to California--do you perceive the Bureau of Reclamation making
emergency declarations to get power online?
Mr. McDonald. If--again, in the context of Glen Canyon, if
the exception criteria for an emergency are met--
Mr. Calvert. And what do you mean by exception criteria?
Will you let us know what you mean by exception criteria?
Mr. McDonald. Yes. In the Record of Decision in 1996, there
were some specific criteria by which, on a short duration
basis, usually a matter of 3, 4, 5 hours, we would operate
outside the bounds of the criteria called for by the record of
decision. Basically those criteria boil down to an emergency
being a situation in which there is insufficient generating
capacity. The transmission system is suffering from an overload
voltage control or frequency problem. We need to run the
generators for system restoration or, in the case of Glen
Canyon, a humanitarian situation such as a search-and-rescue
operation below the dam.
Mr. Calvert. I think since--if it is the--Mr. Shadegg is
here, and since we are on this subject, and this is in his
district, if you would like to ask a couple of questions
regarding Glen Canyon Dam, this is probably an appropriate time
to ask it.
Mr. Shadegg. Thank you, Mr. Chairman. It is--to be
accurate, it is not in my district, but it is in my State, and
we are interested in it.
The record of decision that you refer to, I guess, sets
these criteria with regard to when you can have additional
releases.
Mr. McDonald. Yes, sir.
Mr. Shadegg. I am aware of, I think, three instances
where--I believe--and you can correct me if I am wrong or spell
it out in your answer--pursuant to that record of decision and
under those criteria there have been three instances in the
last, say, 6 months, maybe more, maybe 8 months, where there
has been an additional release, and that has enabled the
California power grid to stay up; is that correct? Are those--
each of those releases been inconsistent with the criteria?
Mr. McDonald. They have in--those instances, in fact, are
cited in my written statement, Congressman.
Mr. Shadegg. My memory tells me one was in September, one
was in December, and one was in March or thereabouts; is that
correct?
Mr. McDonald. Assuming my written statement is correct, I
think the ones we responded to were Stage 3 emergencies
declared by the California independent system operator, and
Western called upon us to generate, and it was an instance in
September, one in February and twice in March.
Mr. Shadegg. Okay. I guess the first question I would have
would be is it your belief that those did any serious
environmental damage, or is it your belief that those did not
do any serious environmental damage in terms of what this
Congress ought to be looking at as we approach a summer where
there may be more of those?
Mr. McDonald. I simply have not seen data one way or the
other on that. If you would like me to check, I would need to
respond on the record. I am just not apprised.
Mr. Shadegg. I would appreciate that because it is an
important question. I mean, I think we want to know--I believe
most of us are concerned about making sure that there is as
much electricity as possible in the entire Western grid,
particularly as we approach this summer where we know, I think,
pretty reliably we are going to be short. If Congress has to
make a trade-off, we want to do it on an informed basis, and so
I would be interested in knowing whether there was
environmental damage by those releases, and then second--and
maybe you can supply us with that information later.
[The information referred to follows:]
Emergency releases made for California occurred on the following
dates: September 28, 2000, February 15, 2001, March 19, 2001, and March
20, 2001. Most were for 4 to 5 hours in duration with the March 19,
2001 event taking place over 10 hours.
The existing program for monitoring resources below Glen Canyon Dam
includes a monitoring schedule, depending on the resource and attribute
being monitored, that means data is collected from two to six times per
year. Given this schedule, the Grand Canyon Monitoring and Research
Center(GCMRC) may not yet have the data to consider the before and
after affects of these emergency releases. The field season for much of
the data collection is just now beginning, and additional information
is likely to emerge throughout the remainder of the year.
Therefore, the GCMRC does not have specific data, at this time, to
determine if the emergency releases caused damage to aquatic resources.
However, the three events in February and March coincided with the time
of spawning of rainbow trout in Glen Canyon. These increased
fluctuations may have caused stranding of redds (eggs) and their
subsequent desiccation. Given the scale of current monitoring
activities, we will only know the effect of these emergency releases
one or two years from now when we evaluate the strength of this year
class in the adult population and even then we may not be able to
determine what events) during the year caused a change.
With respect to critical physical habitat such as sandbars and
beaches, recent studies have shown that the sediment required to
maintain the physical habitat is lost at an accelerated rate through
such peak flows.
______
Mr. Shadegg. Second, could you--should the Congress be
looking at any change in those emergency conditions to allow
additional power production, and if so, would that cause
environmental damage, because I think everybody is interested
in making sure we have electricity. Nobody is interested in
doing environmental damage, certainly not any irreparable
environmental damage or any that is gratuitous or unnecessary.
And so that would be helpful to us if you or your staff--
Mr. McDonald. Okay. We will respond to both of those.
[The information referred to follows:]
The Final Environmental Impact Statement on the Operations of Glen
Canyon Dam and the Grand Canyon Protection Act established an adaptive
management program to cope with the uncertainties in our scientific
understanding of how to manage complex ecosystems. It is based on
collaboration, consensus and sound science. We believe this approach is
the most effective way to develop appropriate management strategies to
meet the interests of the American public including hydropower
production, biological and cultural resource protection and recreation
______
Mr. Shadegg. I think, Mr. Chairman, that is--
Mr. Calvert. I thank the gentleman.
Mr. Shadegg. Those are the questions I have.
Mr. Calvert. Okay. I thank the gentleman.
I promised Mr. Cannon when he returned that he could give
an opening statement, and then we will recognize Mr. DeFazio
for questions.
STATEMENT OF THE HONORABLE CHRIS CANNON, A REPRESENTATIVE IN
CONGRESS FROM THE STATE OF UTAH
Mr. Cannon. Thank you, Mr. Chairman, and I appreciate the
opportunity to be here today. I have come because maximizing
electricity production at the Federal facilities is an issue
that is especially important to my constituents in Utah and to
the West in general, and also I think a matter of major
importance for the whole country and the economy of the
country.
This year my home State and our Western neighbors are faced
with a potential drought, although recent rains have, I think,
helped that somewhat, and an electricity shortage. In Congress
and back home we have been looking at ways to increase the
supply of electricity. The problem is that new power plants and
transmission lines take years to come online. However, it is
important to continue investing in the infrastructure.
We should not ignore the potential of the facilities that
already exist. It makes no sense to me that we are scrambling
to prevent blackouts this summer while generators at Glen
Canyon Dam sit idly each day during peak power demand because
of environmental regulations.
Water from Lake Powell must be spilled at night when power
demand is lowest and held back during the day when power demand
is at the highest. Operating the dam this way has decreased
peak power capacity by a third. This is enough energy for over
450,000 people. Instead of using clean, efficient, and
emissionless hydroelectricity to meet power demand, utilities
have been forced to buy from other energy sources, and the cost
of buying this energy off the market is being passed right on
to consumers, who are staggering under the burden. Glen Canyon
Dam is already built. Its facilities are efficient, modern, and
ready to use. The only thing holding us back from generating
more electricity is regulatory red tape.
I appreciate the work Mr. Calvert and the Subcommittee is
doing to make sure Federal dams are being used in the most
efficient way possible. Again, I thank you for the opportunity
to be here today and look forward to hearing from the rest of
our witnesses.
[The prepared statement of Mr. Cannon follows:]
Statement of The Honorable Chris Cannon, a Representative in Congress
from the State of Utah
Thank you Mr. Calvert, members, and witnesses for inviting me to
address this hearing.
I have come here today because maximizing electricity production at
federal facilities is an issue that is especially important to my
constituents in Utah and in the West.
This year my home state and our western neighbors are faced with a
potential drought and an electricity shortage. In Congress, and back
home, we have been looking at ways to increase the supply of
electricity. The problem is, new power plants and transmission lines
take years to come online. While it is important to continue investing
in infrastructure, we should not ignore the potential of the facilities
that all ready exist.
It makes no sense to me that we're scrambling to prevent blackouts
this summer while generators at Glen Canyon Dam sit idle each day
during peak power demand. Because of environmental regulations, water
from Lake Powell must be spilled at night when power demand is the
lowest, and held back during the day when power demand is the highest.
Operating the dam this way has decreased peak power capacity by one-
third. This is enough energy for over 450,000 people!
Instead of using clean, efficient, and emission-less
hydroelectricity to meet peak power demand, utilities have been forced
to buy from other energy sources. The cost of buying this energy off
the market is being passed right on to consumers who are staggering
under the burden.
Glen Canyon Dam is all ready built. It's facilities are efficient,
modern, and ready to use. The only thing holding us back from
generating more electricity is regulatory red-tape.
I appreciate the work Mr. Calvert and this subcommittee is doing to
make sure our federal dams are being used in the most efficient way
possible. Again, I thank you for the opportunity to be here today, and
look forward to hearing from the witnesses about this issue.
______
Mr. Cannon. Let me just add a question, if I might, to Mr.
Shadegg. He talked about what environmental damage would be
done if there was more peaking. Would you--is it possible to
take a look at what would happen if we went through a prolonged
period of regular daily discharges to meet more of that--or
regular daily peaking need, rather than just the sporadic needs
that we have met in the past?
Mr. McDonald. I think it is important to observe,
Congressman, that the operation at Glen Canyon Dam now, why it
certainly has increased the minimum flows that can be
experienced, and decreased the maximum flows, and put limits on
what we call uprates and--up-ramp rates and down-ramp rates;
also have provisions for attempting to mimic the natural
hydrograph that are well beyond those daily fluctuations for a
few period--a few days in the spring, creating a spike in the
river flow that is designed to redistribute sediment and in
other ways replicate the natural ecology. So it is a much more
complicated question than simply the more smooth daily
operation that we have now relative to historic operations,
because we are also doing some things for periods of time
periodically each year that reflect the complexities of that
ecosystem.
Mr. Cannon. So the question that I would appreciate you
looking at is what would happen to the ecological system
downstream if, for a prolonged period of time, you changed the
current and changed the amount of flow so you met the peak
capacity demands, particularly in southern California and
Arizona on a regular basis, rather than just the four sporadic
flows you mentioned that dealt with the response to the crisis
in California?
Mr. McDonald. I certainly don't know the answer to that off
the top of my head. Very complicated science there. I would be
more than glad to respond for the record based on the numerous
studies and vast wealth of data that is been gathered in the
last 8, 10, 12 years.
Mr. Cannon. Great. Thank you very much.
[The information referred to follows:]
If release constraints were changed in the manner that you
described, downstream change would most readily be seen with physical
and recreational resources. Depending on the timing and duration of the
subsequent releases both rainbow trout below Glen Canyon Dam and the
rainbow trout fishery may be impacted. Recreational river running may
be affected as boats are forced to navigate rapids under changing flow
regimes and rafts and customers are potentially stranded on beaches.
Sediment will be exported from the system at a higher rate and habitat
will be degraded.
______
Mr. Cannon. Yield back.
Mr. McDonald. Thank you.
Mr. Calvert. Mr. DeFazio?
Mr. DeFazio. Thank you, Mr. Chairman. Just following up on
a point the previous gentleman made, I am wondering about
transmission constraints, and I don't know who--whether the
WAPA Administrator can address this or not, but, I look at the
map that is provided on the back of the testimony by Mr.
McDonald, and there is a transmission system constraints map,
and I don't see any big black lines running to Glen Canyon.
Where is that power? It looks like it runs sort of east and
then north and then south and then west. Is that correct?
Mr. Hacskaylo. Yes, sir.
Mr. DeFazio. So, is Glen Canyon really a potential
additional source of supply in the crisis going on in
California, or are we already transmission-constrained in terms
of delivering that power even if it could generate more by,
violating the constraints that protect the Glen Canyon?
Mr. Hacskaylo. The difficulty in moving power from Glen
Canyon to southern California is the lack of adequate
transmission path into the southern California area.
Mr. DeFazio. Uh-huh.
Mr. Hacskaylo. The power plant at the dam and the system
surrounding Glen Canyon was designed to move power into the
surrounding Basin States, not to California. Western has been
able to move some of the emergency power to California during
this past--these past crises by working on arrangements with
other utilities to displace other power flows as we get closer
to California.
Mr. DeFazio. Uh-huh.
Mr. Hacskaylo. And in that--
Mr. DeFazio. Arrangements? We have arrangements? Are we
going to move to a system of market-based transmission where
constraints are resolved by the market as opposed to by these
archaic agreements between utilities to exchange power and keep
the lights on? Aren't you violating the edicts of the Federal--
what do we call it--the Federal Energy Regulatory Commission?
Mr. Hacskaylo. No, sir, not at all. I am pleased that--
Mr. DeFazio. That you are exempt from their harebrained
scheme?
Mr. Hacskaylo. No, sir. I would never call any scheme by
FERC harebrained, and nonetheless, the utilities do cooperate
in times of emergency on a hand shake or by contract--
Mr. DeFazio. Right. That is the old-fashioned way, but we
are being told we are being driven toward an RTO in the West,
and we are being told that despite the fact we have a
constrained system, that what we are going to do is have a
system that is based in markets, and the markets will tell us
where it is constrained, and then they will send us a signal
for 5 to 10 years every day, day in and day out, until we can
rebuild or enforce that system. I just can't believe we are
still allowing utilities to have handshakes and, work in
emergencies and coordinate things and make the system work
better. Why don't we practice this market-based system?
Couldn't they get a lot more for the power? Couldn't they
charge a lot more?
Mr. Hacskaylo. I am not sure.
Mr. DeFazio. Okay. But anyway, we have got a transmission
constraint out at Glen Canyon like we do in about 60 other
places in the Western U.S.; is that correct?
Mr. Hacskaylo. Yes, sir. That is correct.
Mr. DeFazio. Okay. Thank you, and I don't have any other
questions right now, Mr. Chairman.
Mr. Shadegg. Mr. Chairman, as a follow-up to that point, as
I understood your testimony, whatever constraints are there, we
have been able--and I think Mr. McDonald will confirm--we have
been able to get power to southern California essentially, as I
understood your testimony, by shifting it around, and the
articles which I refer to which say--and I have three of them
which I would be happy to put in the record which specifically
credit Glen Canyon Dam with having avoided a shutdown of the
grid. This one is an article dated March 21st. It says, grid
officials credited the influx of 300 megawatts from the Glen
Canyon hydroelectric plant on the Utah/Arizona border, and then
they point out that is enough power for 225,000 homes. A second
article from December 9, again, WAPA crediting Glen Canyon Dam;
and a third one from September 25 crediting Glen Canyon Dam.
There may be, in fact, as pointed out, a transmission
constriction, but it is not such that we can't get power there
through a rotating basis; is that right?
Mr. Hacskaylo. We can get power to southern California on
an emergency basis as we did earlier, but if I may, I might
point out that any additional power generated at Glen on a
nonemergency basis already is under contract to be sold to
customers in the States of Arizona and Wyoming and New Mexico
and Colorado and Utah.
Mr. Shadegg. Sure. So this is available for an emergency?
Mr. Hacskaylo. That is correct.
Mr. Shadegg. It was only able to be done in an emergency?
Mr. Hacskaylo. That is correct, yes, sir.
Mr. Shadegg. Thank you.
Mr. Calvert. Mr. Osborne?
Excuse me. Without objection, those articles will be
entered into the record.
[The articles referred to follow:]
Associated Press Newswires
Copyright 2001. The Associated Press. All Rights Reserved.
Thursday, March 22, 2001
Anglers at risk: River can rise rapidly in power emergency
PHOENIX (AP) - California's energy crisis is turning the Grand
Canyon in a fearful place for fishermen.
Twice this week, Bureau of Reclamation administrators have suddenly
increased the flow of water from Glen Canyon Dam on the Arizona-Utah
border to help meet California's energy needs.
The water powers huge turbines that generate electricity that can
be shipped to California or elsewhere via a grid.
The suddenly rising water in the Colorado River can be a danger for
anglers downstream or below the dam, who may have had little if any
warning.
``I was out there with two clients,'' said Terry Gunn, owner of
Lees Ferry Anglers Guide and Fly Shop. ``And I noticed the water get
murky. Then I heard the volume increase.''
Anglers and campers could be caught in the flow at some places.
They could be stranded. Their supplies on the river beaches could be
washed away.
And there's no way to get a warning out on the river itself: The
sound of a horn wouldn't travel far enough, and the canyon walls block
radio waves.
This week's two emergency releases are half of all that have been
needed in the past year.
March, April and May are prime fishing months for the 16-mile
stretch of river immediately below the dam. The area known as Lees
Ferry widely known for its trout - attracts fishermen in droves, with
or without guides.
The average relatively low flow of 7,000 to 13,000 cubic feet per
second leaves gravel bars and little islands that are great spots from
which to fish.
On Monday and Tuesday, however, the flow through the dam was
increased by more than 7,000 cfs in under two hours. Below the dam, the
flow rose by more than 4,000 cfs in 20 minutes.
In some locations, that would raise the river's level by three feet
in a similarly short span.
Reclamation bureau officials hope they get word of the need from
the Western Area Power Administration farther in advance in the future,
so warnings have be telephoned to guides and others. The administration
brokers power throughout the West and determines where electricity from
Glen Canyon goes.
``We've made a request to Western that we get at least an hour of
warning before we have to ramp up,'' said Randy Peterson, a bureau
official in Salt Lake City.
Overall, however, Peterson said, river users need to be aware that
the water level can change suddenly and rapidly.
Dam operators called the guide services for this week's increases
but only minutes before the new water made it farther downstream.
``We understand that's a power emergency, and there's nothing we
can do about it,'' said Barbara Foster, owner of Marble Canyon Guides
at Lees Ferry. ``But a little more than five minutes' warning would be
nice.''
______
The Washington Post
Copyright 2000, The Washington Post Co. All Rights Reserved
Saturday, December 9, 2000
California Power Grid Is on Verge of Collapse; Deregulation, Repairs,
Pollution Curbs Blamed
William Booth
Washington Post Staff Writer
LOS ANGELES, Dec. 8--The statewide power system in California is
teetering on the edge of collapse.
The governor has turned off the Christmas tree lights, the state
has stopped pumping water from north to south, and universities and
businesses are closing down early. But California is running out of
juice--as demand for electricity outstrips supply in a deregulated
market of wild price fluctuations and potential blackouts.
On Thursday evening, the state's electricity managers at the
Independent System Operator facility declared the first-ever Stage
Three power emergency, meaning electricity supply reserves had dipped
to 1.5 percent of the demand. Rolling blackouts were narrowly avoided
only because extreme measures were taken.
The emergency declaration allowed the managers of the state's power
grid to order electricity that was on its way out of California to be
brought back to the state. The grid was also saved by a last-minute
surge of juice from the Western Area Power Administration, which sent
electricity over the lines from its facility at the Glen Canyon Dam.
And finally, consumers reduced demand. Some were ordered to do so,
while others, such as the California Department of Water Resources,
shut down the pumps that bring water from north to south for crop
irrigation.
The Stage Three alert was canceled two hours after it was declared.
Power supplies were meeting demand today, but energy managers said they
feared for the coming days.
An official at the Independent System Operator said he was most
concerned about rolling blackouts during the foggy evening rush hours,
when traffic lights might suddenly go out.
The problems in California were heightened after the National
Weather Service forecast that severely cold weather from the Arctic
will descend on the central and western United States as early as
Saturday and will continue into the following week.
From the western Great Lakes to the Great Plains, Rocky Mountains
and then the Pacific Coast, abnormally cold temperatures are expected
to accompany fast-moving snow storms.
The National Weather Service said today it appeared that the nation
is finally returning to a ``normal'' winter after three years of mild
winter weather.
An update from the Weather Service late Friday said there was a
decreasing chance that the cold blast will hit California over the
weekend.
In California, the energy crunch has been brought about by a
combination of events.
Dozens of large and small generating plants are off line because of
scheduled or unexpected repairs, or because they were shut down after
reaching their allowed pollution limits for the calendar year.
Today, power usage was expected to peak at around 33,000 megawatts,
while electricity generating plants that could have supplied about
11,000 megawatts of juice were shut down.
About 17 power generation plants--which together produce about
2,500 megawatts of electricity, enough to power 2.5 million homes--were
idle because they had reached their pollution limits.
Managers of at least one electricity generator, San Diego Gas &
Electric, complained that the power system is on the verge of collapse.
They appealed to California Gov. Gray Davis (D) to declare a state of
emergency and to issue waivers to allow the power generators to exceed
their pollution limits during the energy crisis.
State officials who oversee pollution regulations vowed to ease the
restrictions during the crunch.
Davis, whose administration is facing its first real challenge in
the energy crisis, has blamed the power crunch on the deregulation of
California's energy market--deregulation, he and his staff are
reminding voters, that was done by the previous governor, Pete Wilson,
a Republican.
``We're simply not ready for deregulation in California,'' the
governor told the Associated Press. ``California is riding point on
this deregulation experiment. The problem is, I can't control the
process. There are too many players.''
In California's deregulated market, the first and largest in the
country to open the power system to the free market, the electricity
used is produced not only within the state but is also imported from
outside California. While many states export and import electricity, in
California the power is purchased the day before-and sometimes hours
before--it is needed. This was expected to produce lower prices and a
steady supply, but since last summer, supply and demand in the state
have been out of whack.
The Federal Energy Regulatory Commission has labeled the California
electricity market ``dysfunctional.'' Several investigations are
underway to see whether power suppliers are somehow manipulating the
market. Davis and members of the Legislature are meeting to try to fix
the problem. Among the possible solutions is a complete reversal of the
current free market, in which the state would build and operate power
plants.
______
Dow Jones Energy Service
Copyright (c) 2000, Dow Jones & Company, Inc.
Monday, September 25, 2000
U.S. Dam Rescues Calif Grid, But Lawmaker Demands More Power
Bryan Lee
Dow Jones Newswires
WASHINGTON-(Dow Jones)- California averted a blackout last week
with some help from the federal government.
The U.S. Bureau of Reclamation opened the flowgates at the massive
Glen Canyon dam in Arizona, providing 300 megawatts of power for four
hours in the afternoon of Sept. 18, according to federal officials.
The event illustrated how dependent the Western power grid is on
electricity from U.S. government-owned dams, and highlighted the
increasing political tensions that arise from the use of these assets
as competition shakes up the nation's $215 billion power sector.
At a House Government Reform Committee hearing last Thursday, Rep.
Doug Ose, R-Calif., demanded to know why, if the Bureau of Reclamation
was able to help the state avert a grid emergency, it didn't make
electricity available throughout the summer months when San Diego
consumers paid twice as much for electricity as they did in 1999.
``This administration sacrificed the interests of consumers in San
Diego,'' Ose declared.
But a Bureau of Reclamation spokesman said last week's emergency
marked the first time the California grid operator had asked for help.
The Interior Department agency was prepared to act further by
making power available from other dams later in the week, but the
state's grid operator didn't ask for power, said the spokesman, Barry
Worth.
Under a mandate from the Interior Department to restore riverbank
beaches deemed critical for endangered wildlife, Glen Canyon has been
operated for the last few years in a way that reduces net power
production from the dam by about 900 megawatts.
The doubling of flows last Monday was within the restricted range
required by the Interior Department, Worth said.
But he noted the agency was reluctant to do so out of concern it
would interfere with a summer-long test of the impact on endangered
species from drought-simulated low flows.
``The amount we increased was of concern to us initially because of
our test, but we determined the amount was analogous to monsoonal
thunderstorms we would normally get this time of year,'' Worth said.
``We wanted to make sure we were protecting our studies,'' he said.
Nevertheless, Worth noted that power from Glen Canyon doesn't
normally flow to California to begin with. And he emphasized that
transmission constraints don't make the state a natural destination for
the dam's power.
Given the configuration of the Western grid, it is easier for
California to get its power from other sources in the region, such as
Hoover Dam, Worth said.
``We responded, but there's a limitation to how much we can (help)
to begin with,'' he said.
Still, if California asks, the agency is prepared to help by
providing power again, Worth said.
______
Mr. Calvert. Mr. Osborne?
Mr. Osborne. Well, thank you for your testimony. A week ago
we had some folks in from California, and they were talking
about increasing their water storage by about sixfold, and, of
course, some of it has to do with recycling, and some of it has
to do with injection into other systems, but a lot of it has to
do with ancillary dams and storage facilities that were not
necessarily obstructing major waterways, but possibly capturing
runoff. And what I was wondering is if you have any plans or
see any likelihood of increasing your storage capacity?
Mr. McDonald. I presume, Congressman, that you are
referring to the--what we call the CALFED process, the process
involving State and Federal agencies. It is been ongoing in
California for about 6 or 7 years. It is looking at the issues
associated with the Bay-Delta. In the context of that process
and the joint Federal-State decision reached last August, there
were a number of potential new reservoir sites identified in
that process that will be subject to further investigation in
the future. I don't recall, frankly, whether any of those have
hydropower potential or not. I would be glad, again, to provide
those details on the record, but there were about a dozen
additional reservoirs, one of which included the potential
enlargement of a Reclamation facility.
Mr. Osborne. Of course, I would assume if you had more
water storage, it would increase your hydrocapacity, I mean,
even if there were dams off the Glen Canyon, not directly on
the dam itself, but you just had more access to water when you
needed it. But I guess that was my question, whether you knew
of any plans to construct any additional dams or storage
facilities.
Mr. McDonald. Reclamation certainly does not have any
current plans to construct any new hydropower capacity.
Mr. Osborne. Okay. One other question I would like to ask
you, and that is obviously you have been impacted somewhat on
peaking power by the Endangered Species Act and some
environmental concerns, and it may be hard for you to answer
this, but do you feel that there has been sound science and
good data behind those decisions governing the flows and trying
to protect the endangered species?
Mr. McDonald. I think Reclamation believes on the whole,
yes, there has been the best available science brought to bear
on those decisions.
Mr. Osborne. So at times you are varying your flows daily;
is that right? I mean, some increased flows that--at night and
reduced flows during the day?
Mr. McDonald. The more typical change, Congressman,
relative to a historical operation at any given facility is
that we are not ramping up the release of water through a
turbine or bringing it back down as rapidly on an hourly basis
as was historically done. The water still goes through the
turbine. We still generate the energy, but it is not placed on
peak as much as was historically the case.
Mr. Osborne. Okay. Thank you.
Mr. McDonald. Yes, sir.
Mr. Calvert. Thank you.
Mr. Otter--or excuse me, Mr. DeFazio, do you have any
additional questions?
Excuse me. Mr. Otter.
Mr. Otter. Thank you, Mr. Chairman. I have a question
relative to something that was asked earlier.
Is it Hacskaylo?
Mr. Hacskaylo. Hacskaylo, Mr. Chairman.
Mr. Otter. You can call me whatever you want, and we are
even.
Okay. Is there anything close to the free-market system
that has ever resembled the present power marketing, selling,
delivery and control in California in your estimation? Is there
anything close to the harebrained system that they have
instilled down there that is even close to a marketplace
discipline?
Mr. Hacskaylo. I think Californians would agree that it is
an experiment.
Mr. Otter. Well, in the Northwest we call it suffering.
Mr. Calvert. That is all right. I was going to object. We
call it several things, Mr. Otter. But go ahead. I am sorry.
Mr. Otter. My apology. What was the question?
Mr. Calvert. It wasn't a question, just a comment. Some
people call it an experiment. We call it a few other things,
too, but go ahead.
Mr. Otter. I thought I had mispronounced your name, too,
Mr. Chairman. I wasn't sure. Anyway. I just want to pursue
that, because the general public and the news media and some of
those who would like us to believe that that was a failure in
the marketplace discipline in California have failed to call it
what it truly was, and it was a continued mucking about by the
government in the marketplace system, and it was a failure in
restructuring. You cannot have a free market if there isn't a
free market of entry. There is no additional permits for plants
down there, no additional production for hydropower or any
other kind of power, and then you had a fixed price on the
other end, a capped price on the retail market. Anybody that
believes that that was a part of--or had any resemblance to a
marketplace discipline has gotten their economics degree
someplace that--someplace else at a university whose name I
can't pronounce.
Anyway, let me move on to Mr. McDonald. Mr. McDonald,
several weeks ago we got into a discussion about spilling water
in order to click--fix valves on Arrow Rock Dam, which is the
little dam between the Lucky Peak and the Anderson ranch on the
Boise River flows. In repairing those dams--and I was assured
and reassured and reassured again that we would spill no waters
just to fix those valves. Has there been any thought to putting
a pen stock there, some hydroproduction capacities, while you
are fixing those valves?
Mr. McDonald. Private parties, Congressman, in fact, have
an application pending before FERC, and have had for a number
of years, and they could choose to proceed through the FERC
licensing process if they wish to do so. To my knowledge,
Reclamation as a Federal agency has never considered putting a
Federal power plant on that particular dam.
Mr. Otter. And would the Bureau of Reclamation have an
opinion as to whether or not that that would be a good thing to
do, and would you be in support of private sector asking to do
that?
Mr. McDonald. I am not aware that Reclamation ever has
taken a position on that particular proposal. Were it to go
forward, it would go through a comment process. Reclamation's
principal interest on any dam where there is a private party
seeking a FERC license goes to mechanical, structural,
operational kinds of issues just to ensure the integrity of the
structure.
Mr. Otter. Let's say that that were an eventuality that the
permitting process did start. Do you think the Bureau of
Reclamation would fight that? Would they have any resistance to
that?
Mr. McDonald. I really wouldn't have a basis to comment. I
have no personal knowledge of what that proposal may entail.
Mr. Otter. I see.
During the studies on the several lower--what we call the
lower Snake dams, the four dams that were always in question
relative to the salmon runs and the Endangered Species Act,
were you personally involved in those studies as one of the
action agencies?
Mr. McDonald. No. The Corps of Engineers--those are all
Corps of Engineer facilities, and they did the EIS and the
planning study.
Mr. Otter. But in that scoping process, didn't the Bureau
of Reclamation join in?
Mr. McDonald. Reclamation was involved, yes, as a
cooperating agency.
Mr. Otter. I see. But you personally were not?
Mr. McDonald. Essentially not because most of that had
happened before I became Regional Director in Boise.
Mr. Otter. I see. And finally I would ask, Mr. McDonald,
have we changed the mission--the overall original mission of
the construction of some of these dams by rulemaking authority
by agencies, in your opinion?
Mr. McDonald. I would characterize it that we have a new
set of statutes passed by Congress that we are now responsible
to effect, examples such as ESA. That is the law of the land,
and it is a condition that we now need to operate under.
Mr. Otter. Uh-huh. Thank you very much.
Thank you, Mr. Chairman.
Mr. McDonald. Thank you.
Mr. Calvert. Thank you, gentlemen.
Mr. DeFazio, any additional questions for this panel?
Mr. DeFazio. Well, I know in the Northwest--I was just
looking through the Bureau of Reclamation's testimony, and I am
not an expert on California water issues, but I am just curious
when it talks about one of the constraints being contractual
delivery of water. And in the Northwest we actually have--for
purposes of generation and because of the drought--and I assume
the drought is as bad in California as it is in the Northwest--
we actually have the Bonneville Power Administration offering
to purchase out people's contracts which saves BUREC from
having to deliver the water which requires energy. It leaves
more water in the river, which we can use to generate more
energy, and, given the disastrous markets in part created
through some of these poorly written free trade agreements,
puts some farmers in better position than they would have been.
Is anything similar going on in California? I mean, has
there been any attempt, is there anybody who could offer some
substantial price to people who have delivery contracts to--
because I notice here that you say in the summertime you
actually can't even generate enough power to pump the water.
You have to buy power. That is going to be unbelievably
expensive in this manipulated market where you are looking at
300, 500, or currently for August $750 a megawatt hour to buy
power in the manipulated market.
Mr. McDonald. In the Central Valley Project, Congressman,
this summer in the face of the water shortage, Reclamation is
in the process of seeing if a substantial amount of water,
probably in excess of 100,000 acre-feet, north of the Delta can
be acquired from willing sellers from the Central Valley
Project. I am not aware--I would defer to Mike from Western, if
Western has proposed to buy back any load from project pumpers.
I don't think we have and the Central Valley have. That is
only--
Mr. DeFazio. If you buy back a water contract, you don't
have to deliver that water. So that would save you some power,
right?
Mr. McDonald. In the context of what is proposed in the
Central Valley Project, this summer, Congressman, it would be
water purchased north of the Delta that would still be moved
into, through and to some extent pumped out of the Delta to the
south--
Mr. DeFazio. Okay.
Mr. McDonald. --to relieve the shortage on the south side
of the Delta with Reclamation contractors.
Mr. DeFazio. You are going to purchase water to deliver it
to other water contracts.
Mr. McDonald. Yes.
Mr. DeFazio. As opposed to purchasing water to avoid,
having to buy power and/or to augment generation?
Mr. McDonald. Right. This is not a proposition to reduce
load on the system. It is to move water from the current side--
Mr. DeFazio. It is a different issue in California than it
is for us in the Northwest.
Mr. McDonald. Yes it is. That is correct.
Mr. DeFazio. Just wanted to explore it. Thank you.
Mr. Calvert. Mr. Stier, please explain the costs associated
with BPA buying energy off the market. How much has BPA spent?
Is there any number out there right now?
Mr. Stier. In what time period, Mr. Chairman, are we
talking about?
Mr. Calvert. Last year.
Mr. Stier. Well, I am not sure I can break out the power
purchases. We can certainly do that for the record. Beginning
this winter and heading into the summer, I know we have spent
something on the record order of $500 million, both to purchase
power and to purchase industrial and other load reductions in
order to reduce our exposure to the market. So, we have spent a
considerable amount of money on those two areas. I couldn't
break them out individually right here, though.
[The information follows:]
Bonneville's Power Purchases
In order to reduce Bonneville Power Administration (Bonneville)
electric load and conserve water, between the start of December, 2000,
and the end of April, 2001, Bonneville has purchased or curtailed over
3,600 megawatt-months of electric energy at a cost of over $500
million. In addition, Bonneville has netted about 500 additional
megawatts-months of electric energy imported from California under our
two-for-one electric energy exchanges. Total Bonneville short-term
power purchases for all purposes, including load reduction, were $1.083
billion during the first half of fiscal year 2001. Based on published
second quarter of fiscal year 2001 financial results, Bonneville now
expects total fiscal year 2001 short-term power purchases to be $1.547
billion. Total fiscal year 2001 short-term power purchases were $624.9
million.
Mr. Calvert. I have this same question also on Glen Canyon,
and just for the record, how much generation capacity is lost
in the BPA system as a result of environmental regulation? Is
there any estimate on that?
Mr. Stier. Yes. I can give you an estimate. In the Federal
Columbia River Power System, which includes the Grand Coulee
Dam and the various Corps projects, since the 1995 biological
opinion from National Marine Fisheries Service, which was the
first biological opinion issued after we had listings in the
Snake River stocks, has been derated by about 1,000 average
megawatts of firm generation. So, the system was on the order
of about 8,000 average megawatts of firm generation prior to
1995, and it is now something on the order of about 7,000
average megawatts.
Mr. Calvert. So about 15 percent derating or so depending
on--
Mr. Stier. Something like that. Right. We also, of course,
as Mr. McDonald noted, lost a considerable amount of
flexibility in terms of being able to follow loads on a daily
basis. We also have some constraints in terms of seasonal
generation because we are storing water now at times when we
might not have stored it in the past.
Mr. Calvert. What has been the result of that? How are the
salmon doing this year?
Mr. Stier. Well, it is very complicated. There are so many
inputs into the survival of these fish, it is really hard to
say what is working and what isn't. But since a lot of these
measures have been put in place, there have been substantial
measurable survival improvements in terms of juvenile smolts
migrating downriver through the system. We have also had a
period where there have been pretty good ocean conditions. The
fish spend most of their life out at sea. I think the general
consensus is that at least some of what we are doing has been
yielding results. We have had spectacular returns of adults
this year, and there has definitely been an improvement in the
stocks.
Mr. Calvert. Do you think that there is a way that that can
be reevaluated where you can continue to maintain good
environmental policy, but potentially put more power on the
grid?
Mr. Stier. Well, as Mr. McDonald pointed out, we have a
provision in the Biological Opinions we operate under that
allows us to declare a power emergency if we cannot meet
certain criteria. Basically, those criteria are reliability
criteria and financial criteria for Bonneville. We have
declared a power emergency for this month, and it is likely to
be extended pretty much throughout the summer season. That
provision, we believe, gives us substantial flexibility to deal
with the kinds of concerns we are looking at this summer, both
in the Northwest and on the West Coast as a whole.
Mr. Calvert. Okay. Any other questions? Mr. DeFazio?
Mr. DeFazio. Thank you.
What did you say the derated capacity of the system was
with the additional constraints subsequent to the 1995 BIOP?
Mr. Stier. It is about 1,000 average megawatts of firm
generation.
Mr. DeFazio. Right. But what is your total, then, rated
capacity?
Mr. Stier. Well, the firm generating output of that system
right now is just over 7,000 megawatts. That is not peak. That
is just firm generation in a critical water year.
Mr. DeFazio. I was going to say that is a critical water
year, and this is a critical water year.
Mr. Stier. This is actually slightly worse than the
critical water year.
Mr. DeFazio. And what would it be in a better water year--
let's say a normative average water year, what would the system
capacity be?
Mr. Stier. Through the spring and summer of this year, we
will have about 4- to 5,000 megawatts less generation each
month than we had on average for the last 5 years.
Mr. DeFazio. Okay. So at 7,000, you are saying you could
theoretically in a good water year come up with 11-?
Mr. Stier. Right. During the spring and summer. Right. When
we have the runoff.
Mr. DeFazio. But not year round?
Mr. Stier. Not year round.
Mr. DeFazio. Then why did BPA sell 11,000 megawatts in its
contracts?
Mr. Stier. Well, I think you know the answer to that story
reasonably well. For the Chairman's benefit, we have contracts
that go into effect in October. We are contracted to serve
11,000 megawatts of load. Our total system, including the
nuclear power plant that we market the energy from, is about an
8,000 average megawatt firm generating system. There were a
number of commitments made for a variety of reasons over the
course of the 3-year subscription process, to allocate the
power from this system. A year to 2 years ago it seemed
reasonable to believe that Bonneville could go to the market,
purchase the 3,000 megawatts of power that we were short at a
price that was low enough that we could meld it in with the
Federal system and essentially end up with virtually no rate
increase. And of course what has happened in the wholesale
electricity markets has turned that plan on its ear.
So how did we get there? We got there because there were a
lot of folks that wanted a piece of the action. The Bonneville
system was looking very good compared even to the markets a
year ago, and we ended up oversubscribed.
Mr. DeFazio. Did the former administration pressure the
Bonneville Administration to sign contracts with the aluminum
companies who are not entitled under the Northwest Power Act to
additional and continued power provision?
Mr. Stier. Mr. DeFazio, you are really putting me on the
spot, aren't you? Well, let's see. How would I diplomatically
answer that? I guess I would say something to the effect that
Bonneville, consulting with the Department of Energy in the
last Administration and with the region, felt that we could,
with minimal impact on rates, accommodate about 1,500 megawatts
of aluminum industry load, as well as provide approximately
1,000 megawatts of direct power sales to the investor-owned
utilities in the region, which, of course, we had not done
previous to this upcoming contract period. As I said, a year
ago that seemed like a doable proposition without increasing
rates generally, and at this point obviously it is not.
Mr. DeFazio. We have had--in the Northwest Energy Caucus,
an informal group chaired by myself and Mr. Nethercutt, we have
had testimony from public entities that every 100 megawatts
purchased by BPA in the current projected markets would raise
everybody else's rates by about 10 percent. Is that a
ballpark--do you think that is pretty accurate?
Mr. Stier. To my knowledge, that is a ballpark figure.
Mr. DeFazio. So BPA has to purchase 2,500 megawatts for the
IOUs and for the aluminum companies. They can't pass the costs
on just to those consumers. They have to meld them into the
system. That would mean that 250 percent rate increase for
everybody else.
Mr. Stier. That is the worst case we are looking at.
Mr. DeFazio. But there are also other rate increases due to
the drought and other constraints BPA has--in addition, I mean;
250 is not the top. Right?
Mr. Stier. I think the current thinking is that the worst
case is probably somewhere between 200 and 300 percent.
Mr. DeFazio. Two hundred and three hundred percent
wholesale rate increase?
Mr. Stier. Correct.
Mr. DeFazio. Okay. I just saw a statistic today which said
that the Northwest on average--and this is a big surprise to
me--in the spot market is paying more for wholesale power
than--this was in a story about FERC adopting these measures
yesterday, which are not going to really help Californians very
much, but it said that we were actually paying more on average
for wholesale power than Californians. It said 267. We are 267
over the last--how many months was that? Do you remember? It
was in--it was one of the--I can't provide the article, but I
am puzzled by that.
Mr. Stier. You know, I am getting a little out of my depth
here.
Mr. DeFazio. Okay.
Mr. Stier. I can say something, though. I will respond to
that in part though. I do know that the personnel at Bonneville
who do our bulk power trading have a concern about price
controls. Price controls in the recent past, in California,
have tended to distort the Northwest market. That is because
marketers who are subject to price controls in California, but
not in the Northwest, are obviously going to take their product
to the Northwest for a better price if they can get it.
Mr. DeFazio. Well, in fact, FERC's order of last evening
exempts the Northwest and, in fact, for anybody it exempts
outside of a Stage 1, 2 or 3 emergency, it exempts anybody who
brokers power. So all one has to do within California is sell
your power to a third party, and the third party can sell it
without any restriction on price to other Californians. But
obviously I get the idea what has been going on is--because in
some ways what they have done to try and make power slightly
more affordable in California is--has squeezed the balloon and
sent some of that price to us then essentially. Okay. Thank
you.
Thank you, Mr. Chairman.
Mr. Calvert. Thank you, gentlemen.
If there is no further questions for this panel, we will
adjourn this panel and move to our second panel. I thank the
gentleman for coming out, testifying and answering our
questions. You may have some additional questions that we may
submit, and if you could answer those for the record, we would
appreciate it.
Mr. Calvert. Our second panel is Mr. Micheal McInnes,
senior vice president/deputy general manager, Tri-State
Generation and Transmission Association, Inc; Mr. David Wegner,
board of directors of Glen Canyon Institute; and Mr. Rick
Johnson, executive director for science, Southwest Rivers.
If the gentlemen will sit down, we will get going here
shortly.
If the gentlemen will look at lights there on the table,
that is the time indicator, and we try to limit the testimony
to 5 minutes so Members can ask questions of the panel. So
please try to summarize your remarks in 5 minutes or less, and
we will start with Mr. Micheal McInnes. You may begin.
STATEMENT OF MICHEAL McINNES, SENIOR VICE PRESIDENT/DEPUTY
GENERAL MANAGER, TRI-STATE GENERATION AND TRANSMISSION
ASSOCIATION, INC.
Mr. McInnes. Thank you, Mr. Chairman, members of the
committee. I am Micheal McInnes, Senior Vice President and
Deputy General Manager with Tri-State Generation and
Transmission Association, Inc. I am also a member of the
Colorado River Energy Distributors Association. I am sorry.
Mr. Chairman, members of the committee. My name is Micheal
McInnes, Senior Vice President/Deputy General Manager with Tri-
State Generation and Transmission Association. I am also a
member of the Colorado River Energy Distributors Association,
known as CREDA. I am honored to be able to speak to you today
regarding Glen Canyon operations and the marketing of the
Colorado River storage project resources, and some
recommendations on the electric system conditions in the West.
Tri-State is a consumer-owned electric and generation--or
generation transmission cooperative. We serve 44 distribution
cooperatives that have approximately 487,000 consumer meters,
and that translates into roughly a million people of
population. Tri-State is the largest member of CREDA. We also
have coal-fired and gas-fired generation resources, as well as
over 5,000 miles of transmission lines.
CREDA members have entered into long-term cost-based
contracts with the Western Area Power Administration for
purchase of Federal hydropower resources out of the Colorado
River Storage Project. Federal hydropower is marketed pursuant
to marketing plans which have been developed through a public
process, including an environmental impact statement process,
and those resources, as has been mentioned today already, are
marketed throughout New Mexico, Colorado, Wyoming, Utah,
Arizona and Nevada.
Although Glen Canyon Dam has been called on to assist
California three times during these periods of imminent
blackouts, this support was provided as a part of WAPA's
obligation to the Western Systems Coordinating Council, or the
WSCC. CRSP resources are not marketed there on a firm basis, as
has been determined through a public marketing plan process.
The largest generating facility of the Colorado River Storage
Project is the Glen Canyon Dam, located near Page, Arizona. In
1996, after many years of study and $104 million environmental
impact statement, which was paid for by the CRSP power
revenues, Glen Canyon operations were changed. As has been
mentioned, approximately a third of that capacity was lost.
The EIS identifies the annual financial cost to the CRSP
contractors at approximately $90 million. But this is in 1991
dollars, and it is probably three to four times greater than
that in the market today. To date over $134 million has been
spent on Glen Canyon studies and funded by CRSP power revenues,
and this figure does not include the $8 million spent per year
on the Adaptive Management Program.
Last summer, due to a Fish and Wildlife Service biological
opinion, a low-flow experiment was undertaken. That experiment
included low-flat flows, and it reduced generation when it lost
the ability to load follow, which is one of the chief
advantages of hydropower, that ability, as was expressed
earlier, to ramp up and down quickly. The cost incurred by WAPA
and funded by the CRSP revenues was approximately $55 million.
The cost of the experiment alone in manpower and research was
over $3.5 million, also paid by power revenues. The impact to
Tri-State on this occasion was approximately $22 million.
The Western Energy market crisis is affecting all CRSP
contractors and WAPA. As that generation is reduced at the
hydropower facilities, some of that due to environmental
constraints, have caused WAPA and the contractors to be out on
the market. It is the same market that the entities in
California are purchasing from. In order to mitigate, in part,
the effects on this market crisis, Federal generating
facilities should be directed to maximize operations from
Federal hydropower facilities so as to produce the maximum
amount of generation available within the existing legal
constraints. They should also be encouraged to work directly
with the stakeholder and funding entities in making the
decisions that impact those operations, maintenance and capital
improvements at the facilities. Stakeholder involvement,
similar to the 1992 CREDA work program agreement, encourages
system reliability improvements, while ensuring that economic
impacts to customers are addressed.
The success of consumer-owned utilities that in this time
enjoy stable rates can be attributed to a number of things. I
would like to enumerate those quickly: a mix of generation and
transmission facilities and resources, including hydropower,
coal-fired resources and gas-fired plants; long-range
forecasting, planning and construction work programs as opposed
to these short-term market approaches that we see; a pragmatic
approach to electricity supply and demand, where diversity of
load and a sensible approach to providing reserves has created
benefits that are more compelling than customer choice; and
most importantly, that owner/stakeholder involvement and
control.
It is our view that Federal hydropower facility operating
agencies should be directed to maximize production from those
facilities, recognizing existing legal constraints. Research or
experimentation, which would reduce that generation output,
should be temporarily suspended during crisis situations. CRSP
resources are marketed under long-term cost-based contracts
within a defined geographic scope, and they guarantee the
repayment of the Federal investment in these power facilities.
CRSP contractors should not be responsible for the
operational, legal or financial impacts associated with the
Federal Government's assistance to California. And finally,
Federal agencies should be encouraged to implement stakeholder
involvement processes, particularly where the stakeholders are
the funding source for those Federal programs. And I thank you
today for allowing me to appear.
Mr. Calvert. I thank the gentleman.
[The prepared statement of Mr. McInnes follows:]
Statement of Micheal McInnes, Vice President/Deputy General Manager,
Tri-State Generation and Transmission Association, Inc., on behalf of
the Colorado River Energy Distributors Association (CREDA)
Mr. Chairman, members of the Committee, I am Micheal McInnes, Sr.
Vice President/Deputy General Manager of Tri-State Generation and
Transmission Association, Inc., and a member of the Colorado River
Energy Distributors Association (CREDA). I am pleased to have been
asked to talk with you today regarding Glen Canyon Dam operations,
marketing of the Colorado River Storage Project (CRSP) resources, and
recommendations to improve electric system conditions in the West.
Tri-State is a consumer-owned electric generation and transmission
cooperative located in the states of Colorado, New Mexico, Wyoming and
Nebraska. Tri-State is a wholesale provider of resources to 44
distribution cooperatives, that in turn serve approximately 487,000
consumer meters representing a population of about 1 million people. A
portion of Tri-State's resource base is comprised of generation from
the CRSP, of which Glen Canyon is the largest generation resource. Tri-
State also owns coal and gas-fired generation resources, as well as
5,348 miles of transmission resources.
Tri-State is also the largest member of CREDA, which is a non-
profit organization representing consumer-owned electric systems that
purchase federal hydropower and resources of the CRSP. CREDA was
established in 1978, and serves as the ``voice'' of CRSP contractor
members in dealing with CRSP resource availability and affordability
issues. CREDA represents its members in dealing with the Bureau of
Reclamation (USBR) as the generating agency of the CRSP and the Western
Area Power Administration (WAPA) as the marketing agency of the CRSP.
CREDA members are all non-profit organizations, serving nearly 3
million electric consumers in the six western states of Arizona,
Colorado, Nevada, New Mexico, Utah and Wyoming. CREDA members purchase
over 85% of the CRSP power resource.
Tri-State and other CREDA members (contractors) have entered into
long-term, cost-based contracts with WAPA for purchase of federal
hydropower resources of the CRSP. These contracts provide for frequent
rate adjustments in order to ensure repayment of the federal investment
in the CRSP. Our purpose today is to provide some background on the
operational changes at Glen Canyon Dam, to discuss the marketing area
of the CRSP, and to provide suggestions that may assist market
conditions in the Western United States.
The CRSP was authorized in the Colorado River Storage Project Act
of 1956 (P.L. 485, 84th Cong., 70 Stat. 50), as a multi-purpose federal
project that provides flood control; water storage for irrigation,
municipal and industrial purposes; recreation and environmental
mitigation and protection, in addition to the generation of
electricity. This testimony will focus on the major power generation
features of the CRSP, although there are several irrigation projects
included in the Project. The CRSP power features include five dams and
associated generators, substations, and transmission lines. Detailed
descriptions of the CRSP facilities were provided in testimony provided
to this Committee on March 7, 2001.
CRSP MARKETING AREA
Federal hydropower is marketed pursuant to law and marketing plans
that have been developed through a public process. From the time CRSP
resources were initially marketed, the allocations remained constant
until September 1, 1989. In 1979, WAPA began its process of determining
the amount of capacity and energy it would have available after 1989,
and the criteria by which it would be allocated to customers (51 FR
4844, 2/7/86). This process resulted in the ``post-89 contracts''.
As part of this process, it was determined that CRSP resources were
to be marketed pursuant to preference (section 9(c) of the Reclamation
Act of 1939). Also through this process, it was determined that the
geographic area into which CRSP resources would be marketed on a firm
basis ``did not include any portion of California.'' Based on
discussion contained in the marketing criteria, it was determined that
the loads and interest level in California did not warrant expanding
the marketing area into that state. In addition, existing contractors
had made application for the entire amount of generation produced by
the CRSP. There was an environmental impact statement (EIS) performed
on the post-89 marketing criteria. This criteria was again reviewed in
1998, when extensions to the long-term firm contracts were considered.
As part of this process, it was determined that 7 percent of the
existing CRSP marketable resource would be held for allocation to
Native American and new customers, beginning in 2004. (64 FR 34414, 6/
25/99). Also as part of this process, there was a public inquiry
initiated by the Department of Energy, which was intended to assess
whether changes to federal marketing criteria should be made, given the
onset of deregulation. (63 FR 66166, 12/1/98). Ultimately, DOE found no
change was required of WAPA's marketing criteria, which reaffirmed the
concept that the cost-based rates and marketing criteria associated
with the CRSP are still relevant, possibly even more so, in a
deregulated environment. Current customers have committed to purchase
the entire output of the CRSP under long-term contract, through 2024.
These contracts ensure repayment of the federal investment, with
interest, as well as provide a level of resource certainty, which is
critical in current market conditions in the West.
GLEN CANYON DAM
Glen Canyon Dam is located near Page, Arizona and is by far the
largest of the CRSP projects. Glen Canyon Dam began operation in 1964.
The water stored behind the dam is the key to full development by the
Upper Colorado River Basin states of their Colorado River Compact share
of Colorado River water. The Glen Canyon power plant consists of eight
generators for a total of about 1300 MW, which is more than 70% of
total CRSP generation. The ability of the USBR to generate, and WAPA to
market, the total generating capability of Glen Canyon Dam has been
impacted over a period of many years, by various processes and laws.
In 1978 the USBR began evaluating the possibility of upgrading the
eight generating units at Glen Canyon. This was possible primarily due
to design characteristics of the generators and improved insulating
materials. This upgrade was completed, and the generation was increased
from about 1000 MW to 1300 MW. To fully utilize the unit upgrades would
have required the maximum water release at Glen Canyon to be increased
from 31,500 cubic feet per second (cfs) to about 33,200 cfs. The USBR
also studied the possibility of adding new units on the outlet works to
provide additional peaking capacity. The possibility of increasing
maximum releases from Glen Canyon raised concerns with downstream
users. After discussion with stakeholders, the Secretary of the
Interior initiated the first phase of the Glen Canyon Environmental
Studies.
Following many years of study, in July 1989, the Secretary
announced the start of an environmental impact statement (EIS) on the
operation of the Glen Canyon Dam, although no specific Federal action
was identified for study. Meetings were held during 1990 to seek input
into alternatives that should be considered, and the USBR determined
the nine alternatives (including a ``no action'' alternative) to be
studied. Meanwhile, in 1992, the Grand Canyon Protection Act (106 Stat.
4672) was signed into law. Section 1804 of the Act required completion
of the EIS within two years. The EIS was completed and the Record of
Decision (ROD) signed in October 1996.
The result of 15 years of studies and processes is that Glen Canyon
operations were changed to reflect a revised flow regime; approximately
one-third of the generating capacity was lost (456 MW). The EIS
identified the annual financial cost to CRSP power contractors at $89.1
million per year. But this was in 1991 dollars and would probably be 3-
4 times greater today, given energy market conditions. The cost of the
Glen Canyon EIS was approximately $104 million, and was funded by power
revenues collected from the CRSP contractors. To date, over $134
million has been spent on Glen studies, and funded by CRSP power
revenues. This figure does NOT include the nearly $8 million per year
spent for the Adaptive Management Program.
In April of 2000, it was determined that due to hydrologic
conditions and requirements of a 1994 Fish & Wildlife Service
biological opinion, a low flow summer experiment would be undertaken.
The experiment included high spike flows in May and September, with low
flat flows (8,000 cfs) all summer. The purpose was to gain information
regarding endangered humpback chub conditions. The low, flat flows and
hydrology, along with western energy market prices had a severe impact
on power generation, requiring CRSP customers, and WAPA, to purchase
replacement power to meet their resource needs.
The cost incurred by WAPA (and to be recovered from CRSP
contractors) for this replacement power was $55 million, just for the
summer. Twenty-four million dollars of this total is attributed to the
low steady flow environmental experiment; the remainder is attributed
to wholesale energy market prices. The cost of the experiment alone was
over $3.5 million, funded by CRSP power revenues. These figures do NOT
include additional costs to CRSP contractors that had to purchase or
supplement their CRSP resource with purchases from the energy market.
The impact on Tri-State was approximately $22 million.
GLEN CANYON ADAPTIVE MANAGEMENT PROGRAM
CREDA participates on the Federal Advisory Committee charged with
making recommendations to the Secretary of the Interior as to
operations of Glen Canyon Dam pursuant to the Record of Decision and
underlying laws. Funding for the program (Adaptive Management Program)
is through CRSP power revenues. Proposed funding for next year's
program will exceed $10 million. On October 27, 2000, President Clinton
signed the fiscal year 2001 Energy and Water Development Appropriations
Act, which included language (section 204) capping the amount of CRSP
power revenues that can be used for the Adaptive Management Program, at
$7,850,000, indexed for inflation. Without this cap, the annual program
would have continued to increase, with power revenues being the sole
funding source. Now, the program will need to seek appropriated dollars
in order to maintain the increased funding levels. CREDA supports other
sources of funding for this program. CREDA also participates on the
Technical Work Group through consultants, to ensure that good science
and efforts to increase power production are considered.
CRSP contractors have paid, and continue to pay, the majority of
costs at Glen Canyon, even while the Glen capacity has been depleted by
about one-third. There are significant operating constraints on the
remaining available capability, as required by the 1996 ROD.
Recognizing the instantaneous nature of power generation as well as
constraints contained within the ROD, the USBR and WAPA should be
directed to operate the facilities up to the maximum parameters allowed
under the ROD. Maximum fluctuations (down to minimum nighttime flows of
5,000 cfs) should be permitted, which would allow the generation from
Glen to follow load more accurately. There have been situations in the
past where minimum flows were held at 8,000 cfs in an attempt to
placate certain resource stakeholders, who believed there would be
negative downstream effects. Subsequent analysis has disproved that
assumption. Additional generating resource should be made available to
the CRSP contractors within operating restrictions.
MARKET ISSUE MITIGATION
I. GLEN CANYON: The western energy market ``price crisis'' is
affecting all CRSP contractors and WAPA. Reduced operational levels at
CRSP facilities and environmental constraints have caused WAPA and the
contractors to be out ``in the market'' having to purchase resources to
meet contractual obligations and to serve load. This is the same energy
market from which California entities are buying. Unlike merchant
generating facilities that are constructed and operated to make a
profit for their for-profit owners and shareholders, federal hydropower
facilities cannot be operated for for-profit purposes. Their cost-based
rates include many cost components not attributable to merchant plants,
and they are subject to operating restrictions which are generally more
stringent than those placed on merchant facilities.
The CRSP resources are marketed by WAPA pursuant to law and
marketing plans within a legally defined marketing area, on a firm
basis to preference entities. And yet, by Presidential and DOE
directives issued during 2000, WAPA was called upon on September 18,
2000 and again on February 15, 2001, to ``ramp up'' Glen Canyon to
assist the California Independent System Operator avoid blackouts.
Although sympathetic to the energy situation in California, CREDA has
some serious concerns with a requirement that CRSP resources be made
available to California. CREDA's concerns are operational, legal and
financial. Current hydrologic conditions in the Colorado Basin indicate
the potential for another dry summer. Water released this spring may
not be recoverable when it is so desperately needed to meet summer peak
demands. CRSP resources are committed under long-term, cost-based
contracts with a legally defined group of contractors, who are located
within a legally established geographic marketing area. From a
financial standpoint, the CRSP contractors are the ``guarantors'' of
the federal investment in the CRSP. Given the current financial
situation of California power purchasers, CREDA believes the CRSP
contractors must be provided protection from financial impacts which
may result from Presidential or Administration directives which require
WAPA to sell into the California market.
Existing operating parameters in the ROD provide a limited range of
operating flexibility. The ROD contains maximum and minimum flow
levels, upramp and downramp limits, as well as daily fluctuation
limits. However, even within these constraints, the USBR and WAPA
should be encouraged to maximize power production to the fullest extent
possible. They should be directed to temporarily suspend any
experimentation or research that would reduce power output. Research
through the adaptive management program should center on ways to
increase generation without significantly upsetting the balance of
downstream resources, consistent with the CRSP Act's mandate to
``maximize power production''. Such research could also examine the
potential for incremental generation enhancements.
II. STAKEHOLDER INVOLVEMENT: Electric system reliability,
particularly during periods of limited resource availability, is
critical to ensure delivery of electricity to the public. Decisions
regarding system enhancements, particularly to the federal generating
and transmission resources, must take into account both reliability and
economic concerns. A good example of how this type of balance has been
achieved is through a contractual arrangement among CREDA, WAPA and the
USBR.
The common thread among CREDA members is that each one is a party
to a CRSP firm power contract with the federal government. From CREDA's
inception in 1978, the issue of CRSP rate development and application
has been key to its mission. For many years, CREDA's only recourse when
it disputed inclusion of costs or rate methodology was to file at
protest at the Federal Energy Regulatory Commission (FERC). FERC has
authority over federal power marketing administration rates, but only
to a very limited extent. For several years, CREDA explored with the
federal agencies mutually agreeable means of addressing rate issues. In
1983, the USBR and WAPA entered into an agreement that contained
certain principles regarding power repayment study issues, rate issues
and repayment issues. In addition, the agencies agreed to hold informal
meetings with customers prior to proceeding with a formal rate process.
Certainly, this was a step in the right direction.
During the years between the ``1983 Agreement'' and 1992, CREDA
continued to work with the agencies to more fully develop what is
informally known as the ``1992 Work Program Review'' process (Letter
Agreement No. 92-SLC-0208). On September 24, 1992, WAPA, the USBR and
CREDA executed a letter agreement that formally implemented procedures
for customer review of CRSP costs. This agreement was codified in an
amendment to the CRSP firm power contracts with each CRSP contractor.
Under the agreement, CREDA is provided, semi-annually, detailed CRSP
cost information from both agencies. There are procedures by which
CREDA may challenge costs, as well as procedures by which disputes may
be settled. Attempts to resolve disputes begin with negotiation, with
the ultimate step being resolution under the Administrative Dispute
Resolution Act of 1990 (P.L. No. 101-552, 104 Stat. 2736), which
include arbitration. The federal agencies also agreed to cooperate with
CREDA to implement alternative dispute resolution procedures in any
proceeding before FERC.
The 1992 Agreement sets out specific timetables and describes the
nature of the cost information to be provided to CREDA. CREDA retains
the ability to seek resolution in a Court of Law, but has the
obligation to first proceed through the remedies provided in the 1992
Agreement. The benefits of this arrangement accrue to both the federal
agencies and to CREDA members. Members have the ability to scrutinize
work plan information, including proposed capital improvements and
replacements and operation and maintenance expenses, before the plans
become ``cast in stone''. Many CREDA members own and operate generation
and transmission systems; they are able to bring expertise and insight
to the agencies regarding reliability improvements and alternative
construction options. This has proved to be a beneficial relationship
and has resulted in cost savings to the CRSP customers. The agencies
benefit because the parties to the Agreement attempt to resolve
disputed issues prior to the instigation of formal rate processes. In
fact, since implementation of the 1992 Agreement, CREDA has not
litigated a CRSP rate case before FERC. Recently, following extensive
work on the part of all parties during 1999-2000, WAPA was able to
defer a proposed rate adjustment in July of 2000 (saving contractors
approximately $12 million).
The 1992 Agreement was unique at the time it was executed. It
continues to be a good example of constructive stakeholder involvement
with federal agencies, particularly when the stakeholders are paying
the costs of the federal programs at issue.
III. TRI-STATE RECOMMENDATIONS: Tri-State operates over 1,650
megawatts of generation and more than 5,000 miles of high voltage
transmission lines in its own behalf and for others as well as holding
ownership interests in other generation and transmission facilities. As
a cooperative, it is directed by its 44 member electric distribution
cooperatives, representing nearly 500,000 consumers and a population of
nearly 1 million. A cost-based, consumer-owned utility, it is dedicated
to providing sufficient supplies and reliable energy at an affordable
cost.
As a member-owned utility, Tri-State has operated under cost-based
rates and rate stability in an increasingly volatile market,
particularly in the western United States, where consumer concerns over
supplies and costs are steadily increasing.
The success of consumer-owned utilities that enjoy stable,
affordable rates can be attributed to:
1. A mix of generation and transmission facilities and resources
including hydropower as well as coal-fired and natural gas-fired
plants.
2. Long-range forecasting, planning and construction work programs,
as opposed to short-term market approaches.L
3. A pragmatic approach to electricity supply and demand, where
diversity of load and a sensible approach to providing reserves has
created benefits more compelling than choice.
4. And most importantly, owner/stakeholder involvement and control.
CONCLUSIONS AND RECOMMENDATIONS
LFederal hydropower facility operating agencies should be
directed to maximize production from those facilities, recognizing
existing legal constraints. Research or experimentation that would
reduce generation output should be temporarily suspended during
regional power crisis situations. Research to increase generating
capacity from these facilities, without significantly upsetting the
downstream resource balance, should be undertaken immediately.
LCRSP resources are marketed under long-term, cost based
contracts, within a defined geographic scope and guarantee repayment of
the federal investment in power facilities as well as a very sizeable
investment in irrigation projects. CRSP contractors must not be
responsible for operational, legal or financial impacts associated with
the federal government's assistance to California.
LFederal agencies should be encouraged to implement
stakeholder involvement processes, particularly when the stakeholders
are the funding source for federal programs.
Thank you for the opportunity to provide this information and
appear before the Subcommittee today.
______
[A map attached to Mr. McInnes' statement follows:]
[GRAPHIC] [TIFF OMITTED] T1928.014
Mr. Calvert. Mr. Wegner, you may begin.
STATEMENT OF DAVID WEGNER, BOARD OF DIRECTORS, GLEN CANYON
INSTITUTE
Mr. Wegner. Thank you, Mr. Chairman and the committee. My
name is Dave Wegner. I live in Durango, Colorado, and I am here
today representing the Glen Canyon Institute, which is a
private nonprofit entity interested in environmental issues in
the Colorado River Basin.
I am a scientist, and my perspectives today will likely
differ considerably from some of the comments you have heard
previously. For over 20 years, I worked for the Bureau of
Reclamation and, in fact, was the project manager for the Glen
Canyon Environmental Studies which have been discussed a bit
today as spending money that the power users have put forth for
environmental purposes.
I left the Department of Interior in 1996 and since then
have been dealing with environmental issues and dam issues
across the country on the Columbia and Snake River system, in
Alaska and in many rivers internationally. I intend to
summarize my comments today. I have provided you testimony
which provides a more in-depth detail of the points I intend to
make.
We are facing a challenge today. The challenge we face has
many significant questions associated with it. Hydroelectric
dams both built by the Bureau of Reclamation and the Corps of
Engineers were built as multipurpose dams, primarily, though,
with irrigation, flood control and flow management as their
primary goals.
Hydroelectricity and hydroelectric generation was initially
a secondary goal, which today has moved forward and in many
cases it drives and is the primary reason why these dams are
operated. The historic decisions on these dam priorities were
made in a different time, prior to the passage of many of this
Nation's environmental laws. Certainly at Glen Canyon Dam,
which was authorized by Congress in 1956, there was no such
thing as the National Environmental Policy Act taken in to
consideration, and there was no Endangered Species Act. Today
the challenge we are facing is finding ways to maintain the
electrical integrity of this system and still meeting the
mandates of these laws and rules and regulations that the
people of the United States and this Congress have developed to
protect our environment.
The quick and easy approach is to change the operations of
the dam. They are the easiest to turn on and off. It seems like
the simple solution. But we have to look further. We have to
look at what is causing these problems in the first place.
Over the years the impacts of dam construction, operation
and management have been widely debated and been the focus of
many different scientific and administrative studies. The
critical question that should be asked before any change is
made in the management of these Federal dams is who is
benefitting from the power during these emergencies? We should
not be violating these agreed-upon environmental constraints,
rules and regulations if the power is not being used wisely and
being used clearly for emergency purposes.
Some of the findings that I have outlined in my testimony--
and I will just summarize here--go to the core of this issue.
First, the California power crisis is a short-term issue. It
has come upon the scene relatively quickly. Its cause has been
well documented, both in the popular press and in studies and
other testimony that you have heard in other committees. It is
from the previous California State administration not looking
forward to putting on-line more power plants. It wasn't taking
into account clear and useful deregulation legislation.
California has not adopted and developed an aggressive short-
term conservation program, and the current shortage of
electrical supply has developed largely as a result of poor
planning.
As we have already heard today, many of our Federal power
managers have oversubscribed the systems. Bonneville Power
Administration, Western Power Administration, they sell more
electricity than they have the ability to produce. Flow
management has been reviewed extensively. In the case of the
Colorado River and the Glen Canyon studies, we not only have
gone through scientific review, but it has gone through
legislative review, via the Grand Canyon Protection Act that
has gone through judicial review, and we have gone through
extensive administrative review. The environmental regulations
at these Federal dams are not to be blamed for the problems
that occur today. Last but not least, certainly if we continue
to violate these rules and regulations, many tribal and Native
American resources will continue to be impacted.
So in summary, what are some of our recommendations? First,
we need to develop a clear and concise list of criteria and
priorities for when emergencies really are to be called. We
need to develop aggressive campaign and conservation actions to
reduce the power demand. Many of the things that were applied
in the 1970's in the last power crisis need to be relooked at.
We need to develop irrigation buy-back programs for power. We
need to evaluate every direct service industry to see indeed if
there is a more effective way to manage our electricity, and
last but not least, we need to look at how the reservoir
systems are managed.
Providing more electricity at Glen Canyon Dam may not be
the easiest solution. We have already heard that the power grid
does not easily move electricity from Glen Canyon Dam to the
California market. Perhaps it would be more appropriate to use
Hoover Dam to do that.
In summary, the rivers of the Western United States have
evolved over millions of years. We have to be looking forward
to how we, as a group, as a society, can most effectively
develop programs and criteria to evaluate and protect our
resources. Thank you.
Mr. Calvert. I thank the gentleman.
[The prepared statement of Mr. Wegner follows:]
Statement of David L. Wegner, Board of Directors, Glen Canyon Institute
INTRODUCTION
Good Afternoon. My name is David Wegner and I live in Durango,
Colorado, near the Animas River, a tributary to the San Juan and the
Colorado Rivers. I have been asked to provide you with my perspective
on the importance of the environmental and other factors in the
management of the Federal hydropower facilities in the West with
specific reference to the Colorado River basin. Thank you for this
opportunity. My perspective is likely not to be the same as the others
who have testified before you today.
I am a scientist with over thirty years of experience and studies
on river dynamics and environmental impacts. My background on this
issue began on the Colorado River system in 1975 as a biologist on the
Central Utah Project. During my career with the Bureau of Reclamation
(1976-1996) I have had the opportunity to study the Colorado River
system from the headwaters to the Sea of Cortez. Since I left the
Department of the Interior in 1996 I have expanded and applied my
knowledge of dam and river ecosystem relationships to the Columbia and
Snake river systems, in Alaska, other rivers in the Great Basin, and
internationally on rivers in Turkey, Germany, France, Russia, China,
Siberia, Japan, Costa Rica and Vietnam. Many of the problems and
challenges are the same.
I am here today as a representative of the Glen Canyon Institute,
located in Flagstaff, AZ, and also representing the rivers and the
species they support. I intend to address the specific question being
asked by this Committee utilizing my expertise in the Colorado River
system in combination with knowledge gained and drawn from other river
systems in the West.
QUESTION BEING ADDRESSED
Does the current short-term electrical situation in California and
potentially in the Western United States warrant modifying the
environmental rules and regulations that have been developed for the
Federal dams in the West?
BACKGROUND
The river basins of the West are controlled by multiple dams,
irrigation diversions, and pumping plants. In the majority of cases,
rivers with dams cannot support the historical assemblage or biological
diversity of fish and wildlife species that historically were present.
The largest dams in the Colorado River system are Federal and under the
direct control of the Bureau of Reclamation with the hydropower being
managed by Western Area Power Administration. There are over 60
Federal, State and private dams and 17 transbasin diversions that
control the Colorado River plumbing system. In the Northwest, the
Columbia and Snake River system is manipulated by both Federal and
private dams. In the Northwest, the Corp of Engineers and the Bureau of
Reclamation manage the dams while the Bonneville Power Administration
manages hydropower distribution.
These water development systems were planned, approved by Congress
and constructed prior to the passage of the majority of the
environmental laws. The very laws that today make the United States one
of the most progressive nations on the planet recognizes the importance
of our river systems and the species they support. Congress has been
instrumental in the development of the water and hydroelectric
resources of the West and ensuring that the environmental species that
depend on these rivers are considered as equal partners in the
management of the federal dams and irrigation systems.
The rivers of the West are not what they used to be. This has been
documented extensively in many scientific studies conducted by Federal,
State, Tribal and private researchers. Today the rivers are fragmented,
disjointed and severely modified from their former dynamic nature. The
species that depend on these rivers provide economic benefit to the
West. The Federal agencies that manage the rivers are under
Congressional direction to ensure that environmental considerations are
included in the management of the rivers. We are not here today to
debate the value of the dams. It is scientifically documented and
acknowledges that dams have seriously impacted river environments.
When the National Environmental Policy Act was signed into law, we,
as an American people, recognized the importance of our environment and
the species that are supported by them. With the subsequent passage of
the Endangered Species Act, the Clean Water Act, Wild and Scenic Rivers
Acts and other Federal legislation Congress recognized our
responsibility for protecting species and their habitats. Many of the
fish and wildlife species that have been recognized as endangered
evolved and are dependent upon critical habitats and ecologically
functional river systems.
Several examples of the evolution of environmental concerns in
Western river basins are identified below. These efforts are specific
examples of federally mandated actions intended to balance water and
electricity management in the West and include:
LColorado River Fish Program (1980's)
LGlen Canyon Environmental Studies (1982-1996)
LGrand Canyon Monitoring and Research Program
LUpper Basin Fish Recovery Program
LSan Juan River Fish Recovery Program
LFlaming Gorge Dam Environmental Impact Statement
LCentral Utah Project Environmental Impact Statement
LCentral Arizona Project Environmental Impact Statement
LLower Colorado River Multi-Species Conservation Program
LNorthwest Power Planning Act (1980)
LMid-Snake EIS (Bureau of Reclamation)
LFERC Relicensing Program for the Hells Canyon Complex
(Idaho Power Company)
LLower Snake River Dams EIS (Corp of Engineers)
LCALFED, San Francisco Bay-Delta Accord (2000)
LTrinity River Restoration EIS (2000)
LMultiple FERC relicensing efforts ongoing across the West
COLORADO RIVER SYSTEM AND THE EVOLUTION OF ENVIRONMENTAL CONCERNS
The Glen Canyon and Hoover Dams are the primary water control and
electrical production facilities on the Colorado River system. In the
case of Glen Canyon Dam the study of the impact of the operations of
Glen Canyon Dam on the upstream and downstream environmental,
recreation, economic, cultural and Native American issues began in 1973
and continues today.
L1973--Biological Opinion on the operation of Glen Canyon
Dam
L1982--Secretary of the Interior James Watt initiated the
Glen Canyon Environmental Studies
L1987--National Academy of Science Review 1
L1989 - Judicial review of the need for an environmental
impact statement on power marketing criteria for the Colorado River
Storage Project dams
L1989--Secretary of the Interior Manuel Lujan initiates
the Glen Canyon Dam operations Environmental Impact Statement
L1990--National Academy of Science Review 2
L1992 - Grand Canyon Protection Act (P.L.102-575)
L1996--National Academy of Science Review 3
L1995--FINAL Environmental Impact Statement on Glen Canyon
Dam. Over 30,000 public comments received
L1996--Experimental Flood-Environmental Assessment at Glen
Canyon Dam (First application of Adaptive Management at Glen Canyon
Dam)
L1996--Record of Decision on the operations of Glen Canyon
Dam
* LModified flow releases to protect endangered species
* LModified flow releases to protect cultural and public trust
resources in Grand Canyon National Park and Glen Canyon National
Recreation Area
* LModified flow releases to allow for power emergencies
L1999--National Academy of Sciences Review 4
L2000--Glen Canyon Institute--Draft Citizens Environmental
Assessment on the decommissioning of Glen Canyon Dam
What these sequence of actions and efforts illustrate is that there
has been a clear and direct effort made through Congress, the Executive
Branch of the government, the courts and the scientific community to
guide the management of the Federal dams on the Colorado River system
to balance and protect the environmental resources. The decisions that
have resulted have gone through extensive scientific, legislative,
administrative, public, tribal and judicial review and approval
process.
TODAY'S CHALLENGE
Today we are faced with challenges and significant questions
related to the management of the hydroelectric dams in the Western
United States. These dams were historically built as multipurpose dams,
with irrigation and flow management as the primary goals.
Hydroelectricity was a secondary goal that has evolved in many cases to
be the primary driver for operations. These dams were built for
development reasons with many subsidies built in to ensure that the
Federal resource was used. The historic decisions on dam priorities
were made in a different time, prior to the passage of many of this
nations environmental laws. The subsidies of yesterday do not warrant
loosing the important environmental resources of today.
The challenge is finding ways to keep the western electrical system
whole and functional. The obvious and easiest first place to look is
the hydropower facilities. They are easy to turn on, turn off, and have
historically made up the slack for meeting short-term electrical needs.
In the past, the issue would have been done without public input and
discussion. That quick and easy approach cannot be taken today when
other opportunities have yet to be explored.
Over the years the impacts of dam construction, operation and
management have been the focus of multiple scientific and
administrative studies. The result has been a refinement of the
operations of many of the dams in an attempt to balance the
environmental affects with management goals. The list of dam impacts in
published, peer-reviewed documents is extensive and available if the
Committee desires.
A critical question that should be asked before any change is made
in the management of the Federal dams is Who is benefiting from the
power during the emergency? We should not be violating agreed upon
environmental regulations to provide subsidized power to pump
subsidized water so that wealthy corporations can manufacture
subsidized products or so that corporate farms can grow uneconomical,
and subsidized, crops in the desert and leave us with diminished water
quality that kills more species and further degrades marginal lands and
habitats.
FINDINGS
In the course of developing this testimony, several findings are
important to consider.
LThe California power crisis is a short-term issue. It has
been caused by:
* LThe previous state administration not approving any new power
plants.
* LFlawed state deregulation legislation
* LSeven power plants are currently under construction and
another six are on the fast track approval process
LCalifornia has not developed aggressive short-term
conservation incentives.
LThe current shortage of electrical supply has developed
as a result largely of a poorly developed regulatory structure. No
price caps have been implemented, no financial incentive structures are
in place, and as a result, the public power financial capability has
been negatively impacted.
LThe Federal power managers have oversubscribed its
contracts. As an example, Bonneville Power Administration has
approximately 12,000 megawatts of contract responsibility in place and
has the physical resources to supply only 9,000 megawatts. This
requires BPA to purchase an additional 3,000 megawatts of energy on the
open market at prices that are often from 4 to 10 times the cost of the
federally produced power. The result, Federal financial shortfalls; the
solution, don't oversubscribe capacity to produce.
LFlow management regulations in Western River system
Federal dams have gone through extensive legislative, scientific,
administrative and legal review
LEnvironmental regulations at Federal dams are necessary
to balance ecosystem and social needs. These regulations have already
been implemented without significant impact to Federal power contracts.
LCritical Tribal resources will likely be affected by
rolling back of environmental regulations on Western rivers.
LHydropower will continue to shrink in the overall energy
production program due to diminishing capacity of the reservoirs, as
sediment replaces the water and mandated water allocations restrict
delivery ability.
RECOMMENDATIONS
The following recommendations are provided for consideration of
this Committee:
LClosing the gap between electrical supply and demand
through price mechanisms and conservation will go a long ways to
alleviate the current electrical squeeze.
LA need exists to develop clear criteria and priorities
that describe the circumstances for declaring a power emergency and
actions that Western Area Power and Bonneville Power Administrations
would need to take prior to such a declaration.
LDevelop immediately aggressive conservation actions to
reduce the power demand. This would include many of the same activities
were implemented during the 1970's energy crisis:
* LTurn off outdoor advertising signs and lights in public and
private buildings when they are not being used.
* LDevelop irrigation power buy back programs with farmers
* LDo not develop or operate Federal projects that use more
electricity than they produce, such as the proposed Animas La Plata
project.
* LEvaluate every Direct Service Industry to see if Demand Side
Management or other conservation activities could reduce their power
requirements. Examples would be the current temporary shut down of
several aluminum smelters in the Northwest
* LAggressively develop a campaign to educate the public on
conservation measures
LRetire marginal agricultural lands that are growing
subsidized crops that are dependent upon subsidized power for pumping
water.
LMaintain higher reservoir levels at Reservoir Mead by
drawing down Reservoir Powell. This has the benefit of minimizing
evaporation loss at Powell and maximizing power production that can go
directly into the California market from Hoover Dam. This would reduce
transmission losses and maximize operational efficiency.
LThe Glen Canyon Institute urges a measured, scientific
program of reviewing dam management at all mainstem facilities and the
development of ecological sustainable management of our rivers. This
would include a complete economic evaluation of dams, identifying all
subsidies and long-term restoration and maintenance costs necessary to
provide a complete evaluation of dam impacts. Where scientifically and
publicly supported, dam decommissioning and restoration of river
systems should be implemented. In the case of the Colorado River,
meeting electrical needs in California might be better met by focusing
on maximizing Hoover Dam operations rather than utilizing Glen Canyon
Dam.
SUMMARY
The rivers of the Western United States evolved over millions of
years and support species and ecosystems that are economically
important. The regional economics of the West are directly and
indirectly linked to our river systems, whether it be for irrigation,
water supply, salmon and other native species, recreation or
hydropower. Native Americans, local communities and regions, and
millions of people across the country and the world are dependent upon
Congress providing clear and honest guidance in protecting our
environmental resources for now and the future.
Development of the West has resulted in river systems that are
constrained and unable to sustain environmental and economically
important living resources without the regulations that have been
imposed on the Federal dams and restoring ecological integrity. The
long-term ecological sustainability for many of our rivers and the
species that they support are at significant risk if the current
regulations are ignored or administratively rolled back.
The current electrical situation in the West is one that has
occurred because of poor planning, ill-planned and implemented
deregulation actions in California, and the frenzy of private power
interests who are poised to make considerable profit at the expense of
the environmental resources.
The financial integrity of the Federal power agencies can be
replenished as the electrical system becomes whole again. This will
likely occur soon as additional power plants come on-line within the
next twelve months. The damage done to the Rivers and the environmental
resources during the electrical emergency cannot be replenished or
brought back. The rivers and the species that they support should not
be the ones to pay. Congress and the American public have, since 1970,
consistently shown that the environmental resources should be
considered equally with water and power. This is not a time or a place
to violate the trust that the American public has put in its lawmakers
and the responsibility that we all have to the future. I hope you can
find the strength to do the right thing and fully explore all options
to solving the electrical concerns before further compromising our
rivers. Thank you.
______
Mr. Calvert. Mr. Rick Johnson, you may begin your
testimony.
STATEMENT OF RICK JOHNSON, EXECUTIVE DIRECTOR FOR SCIENCE,
SOUTHWEST RIVERS
Mr. Johnson. Thank you.
Mr. Chairman, Members of the Committee, my name is Rick
Johnson. I am the executive director for Science, Southwest
Rivers. We are a nonprofit conservation organization dedicated
to the protection and restoration of the rivers in the Colorado
River watershed. I represent environmental concerns on the Glen
Canyon Dam Adaptive Management Program, where I serve as a
member of the Adaptive Management Work Group, which is a
Federal advisory committee, and also as a Chair of the
Technical Work Group. In addition to my own views, this
statement also represents the views of Jeff Barnard of the
Grand Canyon Trust and Andre Potochinik of Grand Canyon River
Guide, both of whom also serve on the Adaptive Management Work
Group.
Mr. Johnson. The flows of the Colorado River once
fluctuated widely from year to year and season to season. The
power of flood flows eroded and transported a tremendous load
of sand, silt and other fine-grained sediment. Unique plants,
animals and habitats evolved in these extreme environmental
conditions. However, the extensive water developments have
transformed the Colorado from a warm and sediment-laden river
with highly variable flows to a relatively cool and clear river
with stabilized flows.
These changes have had a profound effect on ecological,
cultural and recreational resources in the river corridor. Key
resources include native ecosystems, wilderness areas, world
class whitewater rafting, blue ribbon trout fishing,
archaeological and other cultural entities such as Traditional
Cultural Properties, and threatened and endangered species such
as the humpback chub, Kanab ambersnail and southwestern willow
flycatcher. Dam operations have been implicated in the
degradation of aquatic ecosystems through the loss of native
fish and other species, the invasion of nonnative plants and
animals, and widespread beach erosion. Dam operations have also
diminished whitewater recreational experiences through the
narrowing or rapids and the loss of camping beaches, and
resulted in the erosion of archaeological and other culturally
important sites.
Because of these ecological changes, dam operations are of
great concern to many Americans. The concern is heightened at
Glen Canyon Dam because Grand Canyon National Park lies just 15
river miles below the dam. Grand Canyon is one of the jewels of
the National Park System, it is a World Heritage Site, it is
considered one of the seven natural wonders of the world, and
it is visited by 5 million people every year.
In response to the degradation of resources by dam releases
at Glen Canyon, former Secretary Lujan ordered the preparation
of an EIS in 1989. The EIS was completed in 1995 and the Record
of Decision was signed in 1996. The goal of selecting the
preferred alternative in the ROD was to find an alternative dam
operating plan that would meet statutory responsibilities and
permit recovery and long-term sustainability of downstream
resources while minimizing impacts to hydropower capability and
flexibility.
In the midst of the EIS process, Congress enacted the Grand
Canyon Protection Act of 1992. In essence the act requires a
balancing of benefits derived from water delivery and power
production with benefits to biological, cultural and
recreational resources. In addition, several other authorities
have a bearing on how dams are operated, including the Law of
the River, the National Park Service Organic Act, the
Endangered Species Act and the National Historic Preservation
Act.
The Glen Canyon Dam Adaptive Management Program was an
outcome of the EIS process. The establishment of the AMP was a
revolutionary decision in 1996, as it implemented the
relatively new concept of adaptive management and, I think
importantly, provided for ongoing input into management
decisions by a diverse group of stakeholders.
The Adaptive Management Work Group provides advice to the
Secretary of Interior regarding the effects of dam operations
on downstream resources and any needed modifications to dam
operations to meet the intent of the Grand Canyon Protection
Act. The program serves as a model for resource management
efforts in other areas. A recent National Research Council
report stated that the AMP is a ``science-policy experiment of
local, regional, national and international importance.''.
In conclusion, there are many biological, cultural and
recreational values in addition to water delivery and
hydropower production that the American public holds for the
Colorado River. The Glen Canyon Adaptive Management Program is
an outgrowth of an unprecedented amount of scientific research
and public participation over the past 17 years. Grand Canyon
means too much to the American public to sacrifice the
integrity of this working partnership between local interests
and the Federal Government. We recommend that the current
operations at Glen Canyon Dam are maintained and any potential
alterations be evaluated and recommended through the Adaptive
Management Program.
I thank you for your attention to this very important
matter, and I am happy to answer any questions you have.
[The prepared statement of Mr. Johnson follows:]
Statement of Rick Johnson, Executive Director for Science, Southwest
Rivers, on behalf of Southwest Rivers, Grand Canyon Trust, and Grand
Canyon River Guides
Mr. Chairman, members of the Committee, my name is Rick Johnson and
I am the Executive Director for Science for Southwest Rivers, a non-
profit conservation organization dedicated to the protection and
restoration of the rivers in the Colorado River watershed. I represent
environmental concerns for the Glen Canyon Dam Adaptive Management
Program, where I serve as a member of the Adaptive Management Work
Group (a Federal Advisory Committee) and also as the Chair of the
Technical Work Group. In addition to my own views, this statement also
represents the views of Geoff Barnard of the Grand Canyon Trust and
Andre Potochnik of Grand Canyon River Guides, both of whom also serve
on the Adaptive Management Work Group.
I am delighted to have been asked to speak with you today regarding
the importance of considering environmental and other factors in the
management of federal hydropower facilities, especially in the Colorado
River basin. My focus today will be mostly on Glen Canyon Dam because
that is the system I know the best. However, these comments also apply
to many other hydropower facilities.
Dam operations affect biological, cultural, and recreational resources.
The flows of the Colorado River once fluctuated widely from year to
year and season to season. The power of flood flows eroded and
transported a tremendous load of sand, silt, and other fine-grained
sediment. Unique plants, animals, and habitats evolved in these extreme
environmental conditions. However, extensive water developments have
transformed the Colorado from a warm and sediment-laden river with
highly variable flows to a relatively cool and clear river with
stabilized flows.
These changes have had a profound effect on the ecological,
cultural, and recreational resources in the river corridor. Key
resources include: native ecosystems, wilderness areas, world-class
whitewater rafting, blue-ribbon trout fishing, archaeological and other
cultural entities such as Traditional Cultural Properties, and
threatened and endangered species such as the humpback chub, Kanab
ambersnail, and southwestern willow flycatcher. Dam operations have
been implicated in the degradation of aquatic ecosystems through the
loss of native fish and other species, the invasion of nonnative plants
and animals, and widespread beach erosion. Dam operations have also
diminished whitewater recreational experiences through the narrowing of
rapids and the loss of camping beaches, and resulted in the erosion of
archaeological and other culturally important sites.
Because of these ecological changes, dam operations are of great
concern to many Americans. The concern is heightened at Glen Canyon Dam
because Grand Canyon National Park lies just 15 river miles below the
dam. Grand Canyon National Park is one of the jewels of the National
Park system, it is a World Heritage Site, it is considered one of the
seven natural wonders of the world, and it is visited by five million
people every year. The park is legally charged with protecting native
biological resources and cultural resources, and it provides world-
class recreational opportunities.
Hydropower production needs to be balanced with resource protection.
In response to the degradation of resources by dam releases at Glen
Canyon Dam, former Secretary Lujan ordered the preparation of an
Environmental Impact Statement (EIS) in 1989. The EIS was completed in
1995, and the Record of Decision (ROD) was signed in 1996. The goal of
selecting the preferred alternative in the ROD was to find an
alternative dam operating plan that would meet statutory
responsibilities and permit recovery and long-term sustainability of
downstream resources while minimizing impacts to hydropower capability
and flexibility.
In the midst of the EIS process, Congress enacted the Grand Canyon
Protection Act of 1992 which requires that the dam be operated to ``--
protect, mitigate adverse impacts to, and improve the values for which
Grand Canyon National Park and Glen Canyon National Recreation Area
were established, including, but not limited to natural and cultural
resources and visitor use.'' In essence, the Grand Canyon Protection
Act requires a balancing of benefits derived from water and power
delivery with benefits to biological, cultural, and recreational
resources. In addition, several other authorities have a bearing on how
dams are operated, including the ``Law of the River,'' the National
Park Service Organic Act, the Endangered Species Act, and the National
Historic Preservation Act.
An Adaptive Management Program is in place to ensure that the diverse
interests of the American public are achieved.
The Glen Canyon Dam Adaptive Management Program (AMP) was an
outcome of the EIS process. The establishment of the AMP was a
revolutionary decision in 1996 as it implemented the relatively new
concept of adaptive management and also provided for on-going input
into management decisions by a diverse group of stakeholders.
Adaptive Management is a process to cope with the uncertainty in
our scientific understanding of how to manage complex ecosystems. It is
based on collaboration, consensus, and sound science. We believe it is
the most effective way to develop appropriate management strategies to
meet the interests of the American public--including biological and
cultural resource protection, recreation, and hydropower production.
The Adaptive Management Work Group provides advice to the Secretary
of Interior regarding the effects of dam operations on downstream
resources and any needed modifications to dam operations to meet the
intent of the Grand Canyon Protection Act. The Adaptive Management
Program serves as a model for resource management efforts in other
areas. A recent National Research Council report stated that the
Adaptive Management Program for Glen Canyon Dam is a ``science-policy
experiment of local, regional, national, and international
importance.''
Conclusions and Recommendations.
1. There are many biological, cultural, and recreational values in
addition to water delivery and hydropower production that the American
public holds for the Colorado River.
2. The Glen Canyon Dam Adaptive Management Program is an outgrowth
of an unprecedented amount of scientific research and public
participation over the past 17 years.
3. Grand Canyon means too much to the American public to sacrifice
the integrity of this working partnership between local interests and
the federal government.
4. We recommend that the current operations at Glen Canyon Dam are
maintained and any potential alterations be evaluated and recommended
through the Adaptive Management Program.
I thank you for your attention to this very important matter and
the opportunity to speak to you today. I am happy to answer any
questions that you may have.
______
Mr. Calvert. I thank the gentleman for his testimony. Mr.
McInnes, within existing law what steps can be taken to
increase power production from the Federal hydro-power
facilities.
Mr. McInnes. Well, barriers of new construction such as the
ability to recover investment, environmental requirements which
unduly delay and hinder development, and market theories that
really serve no purpose other than to add layers of bureaucracy
already should be done away with and those things studied. We
certainly are in favor of doing things in an environmentally
friendly way and living within those existing laws.
Mr. Calvert. Do you have any suggestions on what can be
undertaken to alleviate the western energy crisis in the short
term and long term outside of what you just mentioned?
Mr. McInnes. I think we just need to look at those impacts
and make sure we have maximized the use of these facilities
under existing constraints and laws.
Mr. Calvert. Mr. Wegner, if the Glen Canyon Institute
succeeds in developing a Citizens EIS, what do you think your
next step would be to pursue decommissioning of the dam?
Mr. Wegner. The Glen Canyon Institute has published a draft
Citizens Environmental Assessment. Our intent was to encourage
the Department of the Interior to take the next step to do the
complete environmental impact statement to evaluate
decommissioning as one element of the evaluation of the future
for Glen Canyon Dam. If the Department of the Interior
initiates that program, we would like to fully encourage
participation by ourselves and other entities and hopefully get
the full array of potential options for Glen Canyon Dam
identified.
Mr. Calvert. I was led to understand that your organization
actually advocates the Glen Canyon Dam decommissioning.
Mr. Wegner. We advocate the scientific evaluation of
looking at that question and encourage people to evaluate that.
Mr. Calvert. As you heard from today's hearing, we are
trying to explore ways to alleviate the energy crisis not only
in California but really in the entire West. If in fact Glen
Canyon were decommissioned, what would be the source of the
lost 1300 megawatts of generating capacity? Is that also being
investigated through this process?
Mr. Wegner. It certainly would be one of the elements in
the Citizens Environmental Assessment but there are other
alternatives that would also be looked at, such as conservation
opportunities. We would encourage looking at better management
of the remainder of the Colorado River system, looking at other
sources of electrical supply, such as co-generation, other
alternative sources, wind power, solar power, other
opportunities that might be in the area.
Mr. Calvert. How would the water storage capability of Glen
Canyon be replaced?
Mr. Wegner. Glen Canyon Dam was authorized by Congress to
conserve water for the upper basin states. The delivery of
water to the California market is still largely controlled by
releases from the Hoover Dam. So the management of Hoover Dam
and Reservoir Mead would need to be evaluated and taken into
consideration in this process. In the short term the generation
of electricity to meet the needs for California are better met
from releasing more water through Hoover Dam because of the
transmission capability. Capacity from Hoover is directly
connected into the California market, where, as we heard
earlier this afternoon, Glen Canyon is not.
Mr. Calvert. You are aware that Hoover is already at
maximum capability at the present time. We cannot pull more
power out of Hoover, and also in that testimony I point out
that electric power is somewhat fungible. We are doing trade
agreements with the various folks in order to deliver
electricity outside of using existing distribution lines. What
about the impact on recreation in the blue ribbon trout fishery
below Glen Canyon Dam? If the dam were decommissioned, what
would happen to that?
Mr. Wegner. The Glen Canyon Institute's Citizens
Environmental Assessment addresses that. There would be several
ways to decommission the dam and it certainly would not occur
overnight. If it were to occur, it would likely happen over a
20-year period of time. Therefore, the recreational industries
downstream of Glen Canyon Dam through the Grand Canyon would
not likely be directly impacted at all. The trout fishery that
currently exists below Glen Canyon Dam is an artificial trout
fishery. It was not there pre-dam. Changes would happen over
time to that fishery. And as is already in existence below Glen
Canyon, Grand Canyon National Park is actually already managing
for the native fishery and not for the trout fishery. Certainly
changes would occur. Certainly the trout fishery would need to
be looked at, and it would be evaluated through the Citizens
Environmental Assessment.
Mr. Calvert. In that case does Trout Unlimited, for
instance, do they support your position in this?
Mr. Wegner. I have not asked them directly about that.
Mr. Calvert. If in fact the trout fishery did not exist any
more, I suspect they wouldn't be too enthusiastic about it.
Mr. Wegner. No, but on the other hand, Trout Unlimited has
been very supportive in other ecosystems and other rivers
around the country where they are looking at restoring trout
fisheries and native fisheries.
Mr. Calvert. But not necessarily this one here at Glen
Canyon?
Mr. Wegner. I have not asked them directly, sir.
Mr. Calvert. Lastly, the committee is aware when you worked
for the Bureau of Reclamation you were deeply involved in the
Glen Canyon Environmental Studies that led to the EIS and the
Record of Decision.
Mr. Wegner. That is correct.
Mr. Calvert. The key feature of the Glen Canyon ROD is the
concept of adaptive management, which means the dam operations
will not be fixed in concrete forever, but you can adjust those
to reflect new science, new data. In your role as the head of
the Glen Canyon Institute, do you support the concept of
adaptive management?
Mr. Wegner. On the interim basis, and the operations of
Glen Canyon Dam, I wholeheartedly support the utilization of
adaptive management. As the author of the original adaptive
management piece for the environmental impact statement, the
ROD still stands on good science and a good way to balance the
needs. However, if the dam were to be decommissioned, you would
have to reevaluate that whole process.
Mr. Calvert. Okay. Mr. Johnson, your statement says that
you represent the views of Jeff Bernard of the Grand Canyon
Trust and the Grand Canyon River Guides. Does this mean that
those groups also support your testimony?
Mr. Johnson. Yes, that is the case.
Mr. Calvert. Could you please explain to the committee the
process used with the Adaptive Management Program to develop
flow recommendations?
Mr. Johnson. Actually right now we are in the process of
doing that, and the process is that we have an experimental
flow group, which is an ad hoc group which is part of the
Technical Work Group. They get together with the scientists.
They determine what are the major outstanding questions,
research questions, that need to be answered and how they might
be answered with different experimental flows. Those flow
recommendations are then brought to the full Adaptive
Management Work Group and then when we have the appropriate
triggering criteria to run flows of different types, then those
are done, as was done last summer with the low steady summer
flows.
Mr. Calvert. How does this management group work with the
Bureau of Reclamation, which is the owner and operator of that
dam? How does that work?
Mr. Johnson. The Bureau of Reclamation is part of the
Adaptive Management Work Group and their staff have been very
involved and helpful in virtually every one of the
subcommittees, the Technical Work Group and the Adaptive
Management Work Group.
Mr. Calvert. What was the downstream resource impact on the
last summer's steady flow of testing at Glen Canyon?
Mr. Johnson. If I wasn't here today, I would be in
Flagstaff learning about that. There is a science symposium
going on right now, which is the initial reporting of the
results from the flows from last summer.
Mr. Calvert. We would ask that the full written text of
that be entered into the record.
Mr. Calvert. CREDA has testified that the impact of low
steady flow regime on power users was $55 million. What was the
impact on recreation?
Mr. Johnson. From an economic perspective?
Mr. Calvert. Yes.
Mr. Johnson. I am not aware of what it is on an economic
perspective.
Mr. Calvert. Any estimates?
Mr. Johnson. No.
Mr. Calvert. General feelings?
Mr. Johnson. My guess is that it probably had minimum
economic impact. It certainly had an impact in terms of running
flows of 8,000 or flows that a lot of river guides had never
seen before and it took some of the guides some time to figure
out how to run rapids at that level. I know there were at least
three boats running hung up with rocks that had to evacuate,
and so there was that economic impact but a dollar cost
involved with that I don't know.
Mr. Calvert. Mr. DeFazio, do you have any questions?
Mr. DeFazio. No, I am here for the next panel, Mr.
Chairman. Thank you.
Mr. Calvert. There are no questions. So we appreciate this
panel for coming out and answering our questions and
testifying.
We will be happy to introduce our next panel. Our next
panel is Mr. James C. Feider, Electric Utility Director for the
City of Redding; Ms. Aleka Scott, Transmission and Contracts
Manager, Pacific Northwest Generating Cooperative; and Mr.
Richard Erickson, Secretary/General Manager, East Columbia
Basin Irrigation District.
If you will please take your seats, we will ask you to
begin your testimony. You have a timer there in front of you
and it indicates when we get to 5 minutes by a little red light
coming on. We would appreciate if you keep your remarks to 5
minutes or less so we have time to entertain some questions.
With that, Mr. Feider you may begin.
STATEMENT OF JAMES C. FEIDER, ELECTRIC UTILITY DIRECTOR, CITY
OF REDDING
Mr. Feider. Thank you, Mr. Chairman. It is a pleasure for
me to be here from the City of Redding. I am the Director of
the Electric Utility for the City of Redding, and I come from
the perspective of being close to the customer and I face our
customers every day on the streets of Redding and they are
concerned with what is going on in the deregulation fiasco in
the State of California. I am pleased to be here to also
represent The Northern California Power Agency because Redding
and other members of NCPA rely heavily on the Central Valley
Project for the resources to serve their customers. It is vital
to our communities to have that cost based resource to provide
price stability and reliability to our communities.
The Central Valley Project has excellent flexibility to
provide peaking power on a daily basis. However, it has a need
for baseload energy and in order to provide that baseload
energy, the Western Area Power Administration has a contract
with the Pacific Gas & Electric Company, where it trades the
peaking capability to provide firming energy. We are quite
concerned as we sit here today that PG&E is trying to unwind
that arrangement and pass through market rates instead of the
cost based rates that that contract was based on.
I would like to touch on the generation and transmission
aspects of the projects as well. The customers like Redding
have been working closely with the Bureau over the last several
years to optimize the power output, and we were quite pleased
to be able to be participate in the Shasta rewinds that have
now been completed. We are looking forward to turbine
replacements at Shasta Dam, and we encourage this committee to
support further turbine and upgrade activities at the power
plants.
I appreciate the comments made by the Bureau of Reclamation
witness about maximizing off-peak pumping. We would also
encourage Western to have some of its unique customers to also
do off-peek pumping, and I should say also off-peak use of
their facilities. For example, at the Ames Wind Tunnels in the
South Bay area could be further optimized for off-peak
purposes.
On the Trinity River operation we are quite concerned with
former Secretary Babbitt's decision that was made last year. We
think that a more balanced approach ought to be taken. We see
that as a significant hit to both water supply and power supply
in the State of California. We think a more common sense
approach should be used in moving forward.
With regard to the Bureau looking at emergency procedures,
we are concerned that procedures might be too late if the water
is also released. So we would like to see again a balanced
approach.
With regard to transmission constraints in the State of
California in particular, Redding and other municipal utilities
in NCPA support the fix of so-called Path 15 in central
California that you have heard about. The Federal Government
has played a strong role in the past several dozen years on
intertie transmission capacity, and we see the Western Area
Power Administration to be the instrumental agency to get Path
15 fixed.
One of the activities going on as we speak is the
biological surveys. We understand that PG&E has undertaken the
biological surveys, although they say they are not in a
position to proceed with the construction of that project. So
we think the Western Area Power Administration should provide a
key role in facilitating that project either as the lead
Federal agency for NEPA purposes or going forward on the
planning and construction aspects. We encourage this committee
to pay attention to the Fish and Wildlife aspects of this
project because the biological surveys will have to be
submitted to Fish and Wildlife for their consideration.
The last point I would like to touch on is what I call
organizational flexibility. As you know, we are in a crisis in
California and Federal agencies like the Bureau and Western are
to be commended for their ability to operate on a daily basis
to optimize the assets they have. Oftentimes they have to live
with the constraints that have been referred to here today. But
on a day-to-day basis we are pleased that they are optimizing
those resources. However, we think they need flexibility to
respond to the changing conditions. Not only do we have price
instability, but we also seem to have regulatory instability,
and we would like to see those agencies to have adequate
staffing and funding alternatives by those of us who are paying
the bills.
And with that, I will conclude my remarks, and again thank
you for the opportunity to be here.
[The prepared statement of Mr. Feider follows:]
Statement of Jim Feider, General Manager, Redding Electric Utility
Department, City of Redding, California
Mr. Chairman and members of the Subcommittee, I appreciate the
opportunity to testify on behalf of the City of Redding, California,
and the Northern California Power Agency (NCPA).
As Director of the Redding Electric Utility and as an active
participant in NCPA's work with the Western Area Power Administration
(Western) and the Bureau of Reclamation (Bureau), I deal extensively
with the components of the federal power program. Federal power from
the Central Valley Project is a vital component that NCPA's not-for-
profit community members rely on for reliable power at affordable
prices.
The value of the Central Valley Project, also known as CVP, lies in
three subjects that I will focus on today: Generation, Transmission and
Organizational flexibility.
The CVP has been a vital source of generation for NCPA members,
including the City of Redding. It was built to optimize the flexibility
inherent in hydroelectric generation for ramping up during the peak
load hours of the day. However, the actual kilowatt hours produced by
the CVP fall far short of being a good match with customer needs
especially during dry years. That is why Western has historically
purchased so-called firming energy to better utilize the federal system
and to best match customer needs. Western's utilization of its Pacific
AC Intertie facilities has been key to the overall success of the
federal power program.
Also key to the program has been the resource integration agreement
with Pacific Gas and Electric Company (PG&E).
This arrangement was created in 1967 to eliminate the need for the
Bureau to build a base-load, thermal generating station. Unfortunately,
PG&E is currently attempting to unwind this longstanding contractual
obligation to provide cost-based firming energy to Western through
2004. We recommend that the Subcommittee track this substantial
economic threat to the federal power program.
NCPA members have been very active over the last ten years to
ensure proper maintenance and upgrades to the CVP generating
facilities. We are pleased with recent progress made by the Bureau. For
example, advance customer funding to upgrade three generators at Shasta
Dam have resulted in increasing Shasta peaking capacity by about 50 MW.
Turbine replacements allowing further power production enhancements are
underway at Shasta. NCPA believes that turbine replacements at New
Melones, Carr and Spring Creek Power Plants also have merit. We ask the
Subcommittee to support acceleration of these potential upgrades.
With regard to reoperation of the Trinity River, we do not believe
the alternative selected by former Secretary of Interior Babbitt in his
December 19, 2000 Record of Decision (ROD) represents a balance of
competing resource needs in California. In light of the ongoing energy
crisis in California and along with growing concerns over the adequacy
of our water supply, we do not support the substantial increase of
water releases down the Trinity River. We are astounded that the ROD
would be implemented during constant threats of rolling blackouts
especially given that the fisheries on the Trinity River have recently
improved.
NCPA definitely supports stepping up further fishery improvements
such as mechanical work in the Trinity River bed to improve fish
habitat, and we may support some additional water flow as we submitted
during the public process.
We urge the Subcommittee to support a more balanced decision-making
process on any future Trinity decision.
With regard to transmission, NCPA would like to see the federal
government build upon the success story of the California Oregon
Transmission Project. This 340-mile, 500kV Intertie was completed in
1993 as part of a joint effort between Western and 20 public power
utilities. Western's lead role in this project, where 180 miles of
existing federal lines were upgraded, was in large part the reason for
its success.
Western has congressional authority to further enhance the Pacific
Intertie system and could facilitate completion of Path 15
improvements--the transmission bottleneck between Northern and Southern
California. NCPA believes that with an immediate infusion of federal
funding that Path 15 restrictions could be fixed in less than two
years. The most important critical path item is to complete biological
surveys right now during the spring blooming season. We recommend that
the Secretary of Energy be requested to reprogram current year funds
immediately for this purpose. In addition to supporting Western's role
as lead agency, we would like to see Western proceed with work on the
design and land acquisition activities for this project. It is
important to note that any federal funding for this effort should be
reimbursed back to the federal government through user fees or
converted transmission rights as deemed appropriate for the benefit of
the federal power program.
Mr. Chairman and Subcommittee members, California is in a serious
crisis. The federal power system is a vital part of California's energy
picture. Both the Bureau and Western are to be commended for their
daily efforts to optimize generation and transmission assets not only
in partnership with their customers, like Redding, but also for close
coordination with the California Independent System Operator.
As a final point, there is a need for agencies, like the Bureau and
Western, to have considerable flexibility in times of crises. Federal
agencies, which operate significant real power facilities in real time,
need more flexibility to fund and staff their organizations to meet
constantly changing circumstances. NCPA recommends that Western and the
Bureau be given more authority to adjust staffing levels and
alternative funding mechanisms when supported by those paying the
bills. Any increased expenditures would not be borne by the taxpayer,
but rather through Western's customers.
I thank you for the opportunity to testify and would be eager to
answer any questions.
______
Mr. Calvert. Thank you. Ms. Aleka Scott, you may begin your
testimony.
STATEMENT OF ALEKA SCOTT, TRANSMISSION AND CONTRACTS MANAGER,
PACIFIC NORTHWEST GENERATING COOPERATIVE
Ms. Scott. Thank you. Good afternoon and thank you for
giving me the opportunity to update you on RTO West, the
transmission restructuring effort now occurring in the Pacific
Northwest and other States. I am Aleka Scott. I am the
Transmission Manager for the Pacific Northwest Generating
Cooperative, which is an energy services co-op serving the
electric power and transmission needs of 15 rural electric co-
ops in the Pacific Northwest. Because of our extremely
transmission dependent nature, PNGC as a cooperative and I
personally have been involved in all of the transmission
restructuring efforts in the past 7 or 8 years.
The latest restructuring effort is RTO West organized by
the Bonneville Power Administration and the eight investor-
owned utilities in the States of Oregon, Washington, Idaho,
Montana, Nevada, Utah, and parts of Wyoming. While a robust
public process, including participation by transmission owners,
users and other stakeholders, has been established by the IOUs
and Bonneville, collectively known as the Filing Utilities,
ultimately it is the transmission owners, the Filing Utilities
who will decide the content of the RTO Westfiling.
Where are we today on RTO West? The Filing Utilities; that
is, the owners, filed their Stage 1 filing with FERC on October
23, 2000. They asked for a review of governance, scope and
configuration and liability. Work has continued from that day
to this on the issues. FERC just yesterday issued an order on
RTO West. Stage 2 was supposed to be ready in July of this
year, but given the lateness of the FERC order and the enormity
of the task before us and the possibility of unintended
consequences of transmission restructuring, I would hope that
as a region we take the time we need to get it right.
FERC's order yesterday did affirm the basic governance and
scope and configuration and liability parameters of RTOs.
However, what was not filed in the Stage 1 filing and what
remains at the heart of the RTO West debate is the congestion
management and transmission expansion proposal; in other words,
how short term congestion is managed and who decides when to
expand the transmission system. You have heard from many of the
witnesses here today that that is a problem in solving this
entire West Coast energy crisis. RTO West's current proposed
transmission expansion system is based on individual market
participants reacting to high congestion prices sent at over 40
congested points on the transmission system.
Included with my testimony is this map. The yellow
highlights the potential constraints on the system. Relying on
expansion of the grid by individual market participants is
fundamentally flawed. If implemented, it is unlikely to provide
the free flowing highway system that is needed to facilitate a
robust power market, the ultimate goal of any RTO. Given the
current failure of market forces to provide adequate generation
in California we cannot risk leaving expansion of regional
transmission grid to individual market participants when the
very conditions necessary for a competitive market do not exist
in the monopoly transmission system, and my testimony gives a
more detailed explanation of this.
Gentlemen, consumers expect utilities to plan and take
action to meet growing demands. They expect the lights to stay
on and they expect reasonable prices. To create an RTO without
the responsibility and authority to anticipate and take action
to meet transmission demands would be viewed as a breach of the
public trust. Because Bonneville, a Federal agency, owns 80
percent of the transmission system in the Pacific Northwest,
defining Bonneville's role is critical to RTO West.
Specifically, Bonneville must insure three things: 1) That the
RTO system is able to anticipate the needs of the transmission
system in order to facilitate the power market; 2) that the
costs and risks of current operation and future expansion not
be shifted onto small and rural electric utilities; and, 3)
that the RTO system of congestion management and expansion not
increase or contribute to the volatility of an already chaotic
power market. The answer is to give RTOs the responsibility and
authority to plan and expand the system in a timely manner and
spread these costs broadly to the users of the system instead
of relying on individual participant responses.
Briefly, why will the currently proposed RTO West system
not work? It requires users to experience high prices for long
periods of time. Expansion of system then takes 5 to 7 years
due to planning, permit, construction and rating. Simply put, a
user-based system will not respond in a timely manner. Our idea
is to give RTO West more authority for planning and expansion
of the grid. I want to be clear that this proposal still relies
on giving investors who offer long-term solutions to the RTO a
fair return on their transmission projects or alternate
projects. In this way we are still relying on the market for
expansion.
I would like to leave you with one closing thought. Rome
was not built in a day nor will a Westwide RTO come into being
overnight. FERC acknowledged in its order yesterday that RTO
West is the anchor for the ultimate Westwide RTO. Let's not
frustrate our purpose by trying to get to a Westwide RTO too
quickly. I encourage you to investigate the RTO effort further.
[The prepared statement of Ms. Scott follows:]
Statement of Aleka Scott, Transmission Manager, PNGC Power, Portland,
Oregon
Mr. Chairman,
Thank you for this opportunity to testify today. My name is Aleka
Scott and I serve as the Transmission Manager for PNGC Power. The
issues being discussed at today's hearing are very much on the minds of
Northwest electric utilities and their customers. We very much
appreciate the opportunity to share our views.
PNGC Power is a Portland, Oregon based electric services
cooperative owned by 15 electric distribution cooperatives serving
customers in 7 Western states. Our role is to aggregate the loads of
those systems, establishing and managing wholesale power arrangements
to meet their needs. Our members are all in rural areas and, as such,
depend on the transmission systems of the Bonneville Power
Administration (BPA), Northwest investor-owned utilities and some
select public power systems for the delivery of wholesale power. I have
attached a service territory map indicating the areas served by our
member/owner utilities.
PNGC Power has been a strong supporter of the establishment of a
Regional Transmission Organization (RTO). We continue to believe that a
properly structured RTO could deliver great efficiency and reliability
benefits to the Northwest region. Such an organization could provide
affordable access to the wholesale power market by all wholesale
utility buyers, not just those fortunate to be connected directly to
the BPA grid, or to high voltage sections of other transmission
providers' transmission systems. Any RTO established in the Pacific
Northwest must include the transmission assets necessary to ensure
transmission access to these utilities. Without inclusion of all the
necessary facilities, including those of the Bonneville Power
Administration the possibility of market power and vertically pancaked
rates continues to exist.
Unfortunately, as I will describe, we continue to have doubts that
the outcome of current regional RTO efforts--called ``RTO West'' will
establish more efficient, less costly service to electric consumers. We
are actively involved in the RTO development process with the hope that
we can alter its provisions to the better.
Background on RTO Efforts in the Pacific Northwest
RTO West is not a west-wide entity but rather includes only the
states of Washington, Oregon, Idaho, Montana, Nevada and Utah. For
reasons stated further below, we believe it is inappropriate to include
California in our RTO.
The goal of regional stakeholders--including PNGC Power--involved
in the RTO-West process is to file a plan with the Federal Energy
Regulatory Commission (FERC) that meets the needs of both transmission-
owning utilities and transmission dependent ones. While it is the
responsibility of FERC-jurisdictional utilities in our region to
ultimately make that filing, they will not solely determine whether it
is successful. The Bonneville Power Administration owns about 80
percent of the transmission assets in the Pacific Northwest region.
BPA's assets connect the region from north to south and, without them,
there effectively is no RTO West.
As a federal agency, BPA has to look to Congress for direction and
oversight on matters as consequential as whether to participate in RTO
West. We are encouraged that the Subcommittee has included this subject
at today's hearing because, in providing that direction, it is critical
that you hear from those of us that will be affected by BPA's decision.
As preference customers of BPA, our members cannot favor an RTO which
produces a less reliable transmission system or one that imposes far
more costs and risk on individual users of that system. We encourage
you to continue to exercise your oversight responsibility to determine
whether BPA's participation will ultimately be to the benefit of actual
consumers.
Why RTOs? Why now? RTOs are FERC's next step along the
restructuring road to produce robust, fully functioning power markets.
Transmission, a monopoly service, is the transportation piece of this
electric commodity market and has in the past been used as a strategic
asset to block, limit, or collect monopoly rents from power sales.
Transmission owners were able to price transmission well over its cost-
basis, effectively taking a ``piece'' of the power sales transaction.
Often this was a disproportionately large piece.
The Energy Policy Act of 1992 gave FERC new authority to order
transmission service and FERC responded with the issuance of Orders No.
888 and 889. Transmission was to be open to all at the same terms and
conditions that transmission owners made transmission available to
their own merchant functions. Separating the transmission arm of
utilities from the merchant (generation) arm of the same utility was
required. However, abuses continued and FERC issued Order No. 2000
calling for the voluntary (or all but mandatory) formation of RTOs. The
idea was to form large, independently operated transmission grids,
which would enable the free flow of power within a region without
pancaked rates or opportunistically exercised transmission market
power.
In the Pacific Northwest, incumbent transmission owners and
stakeholders have been working on restructuring the transmission system
for over 5 years. Previous efforts, while they have not come to
fruition, have laid the groundwork and advanced the level and depth of
discussion regarding regional transmission organizations.
Currently, transmission owners in the states of Oregon, Washington,
Idaho, Montana, Utah, and Nevada, have formed themselves into a group
called the Filing Utilities and are working to form RTO West. RTO West
would encompass most of the transmission in these western states. RTO
West has a sounding board, called the Regional Representatives Group
(RRG), made up of 24 members of ``stakeholder'' groups such as
cooperatives, other public power systems, power marketers, independent
power producers, conservation organizations, state representatives, as
well as representatives from the Canadian provinces of British Columbia
and Alberta. Working underneath the RRG are technical work groups that
are open to any interested party. The decision process calls for
consensus items to be preserved in the filing, with the Filing
Utilities deciding on matters where consensus does not exist.
Ultimately, because of the diversity of opinion, it is the Filing
Utilities who will decide the bulk of what is included in any RTO West
filing to FERC.
RTO West made a Stage 1 filing to FERC in October of 2000 and asked
at that time for an expedited ruling. At this writing, FERC is expected
to issue an order on the RTO West Stage I filing in the next few days,
which means the clock continues to tick and final decisions about the
structure and composition of the RTO must be completed shortly. The
Filing Utilities and other involved parties have continued to work on
Stage 2 of the RTO West development. Issues which remain open include
congestion management, development of a tariff, how the transmission
grid will be expanded, development of the scheduling coordinator role,
the translation of existing contracts into rights and dollars in the
RTO West world, as well as how unconverted contracts will operate.
There are many, many policy and technical issues still to be resolved.
Congested Transmission System
In the geographic area covered by RTO West we face an ever more
congested transmission system. Why is this system, which only 5 or 6
years ago had minimum congestion, now so congested? There are four
reasons. First, loads have continued to grow steadily. Secondly,
because of the uncertainty surrounding recovery of transmission
investment, very little new transmission investment has been made in
that timeframe. Thirdly, the system is being used in ways it was not
designed for in order to accommodate more and more market activity. And
lastly, the outages of August 1996 triggered the study of simultaneous
operation of many paths which had not previously been studied together.
These studies have often resulted in lower operating limits on existing
lines than prior to those outages.
Transmission Expansion
BPA's transmission system is now more constrained than at any time
in its history. Other transmission systems in the RTO West area also
have more transmission requests than transmission capacity. If RTO West
does not have adequate expansion authority, we believe that the
reliability of the system will be placed in jeopardy. Reliance on
individual users receiving market-based congestion pricing signals for
transmission expansion across congested flowpaths is misguided, and for
the reasons explained below, expansion is not likely to occur. If this
type of expansion mechanism is implemented by RTO West, it is likely to
have the effect of creating multiple load islands--in effect, islands
of market power due to unrelieved constrained transmission capacity.
The result of this market failure will be extremely high and volatile
prices for transmission rights across flowpaths and into load islands.
Instead, the RTO needs to have the authority to plan and expand the
transmission system. It is essential that the RTO put in place a
mechanism that actually encourages the relief of constraint points
instead on institutionalizing them. The underlying worldview here is
that congestion is ``bad''. Congestion constrains trade and results in
less efficient use of resources. In an ideal world, there would be no
congestion and power markets would flow freely. We need to bear in mind
that an RTO is supposed to be the antidote to transmission market
power, the antidote which allows for the most robust power market. To
establish an RTO that monetizes the value of congestion but does not
put a workable method in place to relieve congestion simply creates
more market power and, more ability to make excessive profits.
Ultimately, consumers lose.
There are many reasons why a user-based market-driven expansion
program is unlikely to succeed. Foremost of these reasons is that the
transmission system is a single unified machine that essentially is a
monopoly. No transmission system can meet the requirements needed for a
user-based market expansion to work. For this type of expansion to
work, transmission expansion would have to meet the requirements of a
competitive market. The requirements for a competitive market are a)
low barriers to entry, b) many buyers and sellers, c) ready access to
market information, and d) that no single buyer or seller can make the
market. None of these conditions are met in the transmission expansion
arena as discussed below.
a) The first requirement of a competitive market is low barriers to
entry. Transmission expansion has enormous barriers to entry.
Transmission expansion projects tend to occur in large size increments,
often more than any one user or even groups of users can utilize in the
near-term. For example, if a party needs an additional 100 MW, the
expansion available is likely to be a 500 MW expansion. Transmission
expansion is dictated by the physics of electricity, not the additional
capacity needed by a market participant. These transmission additions
are long-term, capital intensive assets. Typically they have service
lives of 40-50 years. Few market entrants, if any, have 40-50 year
investment paybacks and fewer still have access to the capital
necessary to build transmission. Another barrier to entry is the
complexity involved in building transmission, from siting right-of-way
to permitting to actual design and overseeing the construction. Five to
seven years is the industry standard lead-time for building
transmission additions. This kind of lead-time in itself is a barrier
to entry for many, many potential participants, in an industry where
companies can be wiped out by just a few bad trades.
Substitutes for transmission expansion can be strategically placed
generation or demand-side programs on a scale large enough to forego
transmission additions. These substitutes are also not ``low barrier to
entry'' activities but certainly have a role as alternatives to
transmission. However, we believe these substitutes have a limited role
and will never fully supplant transmission construction. Further, the
signals for these transmission expansion substitutes are, on the whole,
better implemented by an RTO in the form of incentives rather than
through a complex, cumbersome, and highly volatile congestion-pricing
scheme.
b) ``Many buyers and sellers'' simply does not describe the
transmission system. Transmission has always been a monopoly, or at
best, oligopoly business. RTO West is no exception. In addition, as
currently proposed in Stage 1 RTO documents, each of the existing
transmission owners will still retain a first right of refusal to build
transmission additions, perhaps at any price. Some will argue that
there are substitutes for transmission such as generation or demand-
side programs. While these measures may be transmission substitutes in
some cases, they are certainly not the universal substitute for
transmission that some would portray them as. Often, the only answer to
a transmission problem is a transmission addition. If an area is
constrained by transmission limitations, by definition the access of
many buyers and sellers is limited. In such a constrained transmission
area, a generator or a holder of firm transmission rights can exercise
market power. Thus the second part of our test for the existence of a
competitive transmission market--many buyers and sellers--fails.
c) A competitive market requires good access to market information.
The role of RTO West is still unclear in this area. Some argue for the
RTO to have full planning capabilities while others argue that the
RTO's role should be confined to simply identifying problems but
leaving the fixes to the ``market''. The market however will not
receive the price signal that a path is congested until it actually is
congested. This signal, high prices, will have to be experienced for a
reasonable duration in order for parties to be motivated to fix the
congestion. At this point however, it is too late. Transmission
construction takes 5 to 7 years given the complex design, permitting,
procurement, and construction involved. The proposed RTO West market-
driven expansion system implies that the transmission customers will
have to feel the pain of the high market price for 6 to 9 years before
it is relieved. Judging from the unwillingness of nearby jurisdictions
to allow price signals to reach the consumer level and the long lead
times involved in transmission planning and construction, it is unclear
that a market-driven expansion system will deliver the best value for
consumers. Instead, RTO West should be vested with the clear ability
and authority to plan and expand the system in a timely manner to avoid
the kind of catastrophic shortages now being experienced in California.
d) Lastly, in a competitive market no one party can make the
market. If a private party does expand a transmission flowpath and
receives all of the physical rights associated with the expansion, they
become the market maker on that path.
We are highly skeptical that user-based market-driven expansion
will work; rather, we need to build an RTO that can assure the region a
robust and reliable transmission system. Persistent transmission
constraints, even those caused by commercial congestion, can endanger
reliability and prevent development of a fully competitive power
market. The RTO must have the authority to compel the transmission
owners to construct or to allow third parties to build transmission
additions, and to allocate the costs to the appropriate transmission
owner or owners in a timely manner.
Aside from planning and expansion issues, there are other equally
critical issues.
Facilities Inclusion
In the Pacific Northwest, , there are over 100 public and
cooperative electric utilities serving a diversity of residential,
commercial and industrial loads. Each of these utilities is a wholesale
power customer. Not all of the transmission facilities needed to reach
wholesale power customers are included in RTO West. The lack of
inclusion of secondary transmission between the RTO West transmission
system and many wholesale utilities' points of delivery potentially
subjects utilities to vertically pancaked rates, double or triple the
regulatory burden, and multiple planning and expansion forums required
to ensure reliable service. The net result could be a large increase in
transmission costs for utilities that are faced with a gap between
their wholesale point of delivery and the proposed RTO West system.
Because RTO West may not include all the transmission facilities
required to reach wholesale utilities, RTO West will not be able to
ensure the reliability of the entire transmission system needed for
load service. One goal of an RTO should be to consolidate transmission
forums and allow transmission to be easily accessible in a one-stop
shop type of organization. Proliferation of the number of forums that
address transmission issues, due to exclusion of some transmission
facilities, is completely contrary to the intent of an RTO.
Complexity
If the RTO West system was reasonably free-flowing and had 3 or 4
congestion points, the RTO West model for congestion management might
work well. FERC acknowledged in its Order 2000 that ``while the
approach of trading physical transmission rights in a secondary market
may prove to be workable in regions where congestion is minor or
infrequent, in other regions where congestion is more of a chronic
problem, it may not be workable.'' [Docket No. RM99-2-000, Order No.
2000, pg. 383] The market driven expansion mechanism relies on price
signals being sent over each flowpath. A flowpath is a line or set of
lines across which there is commercially significant congestion, also
referred to as a constrained or congested path. Because of the large
number of potential flowpaths in the RTO West system (see attached
map), the congestion management system is likely to result in an
extremely burdensome administrative system for scheduling, billing, and
procuring transmission while not providing adequate incentive for
transmission construction.
Because the user-based market-driven mechanism relies on price
signals across flowpaths, the information and flow-based infrastructure
required not only by RTO West, but also by all the parties who must
interact with RTO West, will be significant. If a user-based market-
driven mechanism is to be used for expansion, a significant number of
transmission planners will be needed to make the model work. Some
things money cannot buy, and at the moment, transmission planners are
on that list. In short, the investment needed in infrastructure and
personnel appears to be large compared with the benefit of a user-based
market-driven expansion system, which seems dubious at best.
Translation of Existing Rights
As contracts are converted from their current form into the flow-
based RTO world, we must ensure that existing transmission rights to
serve loads are preserved, including any provisions for load growth and
peaking. Most BPA preference customers have Network Integration
contracts with BPA that require the agency to serve the transmission
requirements of the customer, including load growth and any peaking
requirements for which these customers pay a ``transmission load
shaping'' charge.
In the RTO world, the initial allocation of rights will be limited
to a historic period using a ``feasible dispatch'' of generation. Firm
transmission rights for load growth will be allocated one year at a
time, subject to available transmission capacity. However, this could
well leave any individual utility customer short on firm transmission
rights during an extreme weather event, due to heavy loading of the
transmission system from exports, or due to a generation dispatch
different from the feasible dispatch used to allocate rights. The
result on the load-serving utilities will be either extraordinary
prices for firm transmission rights or load curtailment. In this way,
the RTO model moves risk from the BPA transmission business to its
individual customers without providing compensating value.
RTO West Model Disproportionately Impacts BPA Customers
BPA's customers are in a unique and unfortunate position. Each IOU
will receive physical rights (firm transmission rights or FTRs) on the
transmission system to serve its native load. The IOUs will be able to
take advantage of the diversity inherent in a large block of load and
continue to serve the transmission needs of their native load much as
before. BPA, however, has no native load. Instead, it has over 100
separate wholesale customers: corporate or governmental subdivisions
called wholesale utilities. If these customers want to convert to RTO
West service, physical rights will be assigned to them based on their
load. The inherent diversity of loads that BPA captures through the
current system to meet all of its customers needs will be lost. It is
not gained by any other party; it is lost to the region as a whole due
to the RTO West model. BPA's former transmission customers, many of
whom are small utilities, will assume a level of financial and
operational risk that was previously managed in the aggregate by BPA.
In this case, the sum of the parts is greater than the whole because of
load diversity; and it is those parts which bear the additional costs.
This effect is inherent in any congestions model which requires
numerous flow paths. Moving towards a model which internalizes many of
the constraints and gives the RTO the positive responsibility and
authority to relieve the congestion long-term using market-driven
expansion, as well as the tools to clear congestion in the short-term,
is an option which works. It requires the willingness of the current
transmission owners to give real authority to the RTO. PNGC is
advancing just such a proposal at the current time.
Conclusion
There are some serious flaws in the RTO West model at present. We
at PNGC are working to make the RTO West model more workable, not just
for PNGC's cooperative members, but for the whole region. As part of
those efforts, we have proposed an alternative congestion management
model which has few zones, allows the RTO West to recapture the
diversity of the system, and actively relieves congestion long-term. It
is critical that our region stay open to these types of solutions. It
is not an understatement to say that the transmission system is the
underpinning of our regional economy. The transmission system is what
allows for a free-flowing, robust wholesale power market.
RTO West has 12 work groups, each of which is vitally important to
the proper functioning of the transmission grid. RTO West is creating
out of whole cloth an entirely new way for the transmission system to
operate. We need to take the time necessary to be sure that this
restructuring is thoroughly thought through and carefully implemented.
The possibility for adverse unintended consequences is huge, as the
California experience has shown us. We are still hopeful that
reasonable solutions to the above problems can be crafted. However, at
this point, we can not say if the RTO West final proposal will meet the
needs of the region or not. We urge the Congressional delegation to
learn about these very complex issues and to take an active interest in
RTO West in order to safeguard the reliable delivery of our region's
most vital product, electricity.
As stated above, we believe that the RTO West proposal will live or
die based on the BPA's participation. At present, we are not prepared
to support that participation until we have more comfort that BPA's
utility customers will be able to operate in the new environment in a
way that is efficient and cost-effective. This is a critical point that
we believe warrants further Congressional oversight. BPA should not
participate in RTO West without the support of its customers and of
Congress.
We believe that BPA and the IOUs need to begin transmission
improvement programs now and should not abdicate this responsibility to
the so-called user-based market-driven mechanism. In the Northwest, BPA
owns about 80 percent of the transmission assets. It is essential that
the IOUs be willing to step up to the plate and share in the costs of
BPA's transmission expansion program, recognizing that a free flowing
power system within the Northwest benefits the entire Northwest
economy. Compared to the cost of power today, these improvements are
relatively minor in the overall cost of delivered power. As a region we
cannot wait for RTO West to be established and then hope that the user-
based market-driven expansion will work.
Let me leave you with a parting thought--No West-Wide RTO. At the
meeting which the FERC held in Boise on April 10, 2001, the
Commissioners heard from representatives of 11 states. There was broad
recognition at that forum that it was impractical at this time to
institute a west-wide RTO--adding California and other areas to those
already contemplated in RTO West. Each region has a unique history and
topology concerning transmission. Forming regional transmission
organizations has involved incredible levels of effort and compromise
and we, as a region, are not there yet. Each region must take the first
step of forming regional RTOs with recognition of the issues at the RTO
interfaces (so-called seams issues). Eventually, either adequate
treatment at the RTO seams or a west-wide RTO will evolve to truly
unify the western interconnection.
At the moment, California has its own crisis with which to deal. To
force other regions with their own traditions and practices to come
together with California at this time is a recipe for revolt and
disaster. Certainly, BPA's customers would not stand for BPA throwing
its Federal Columbia River Transmission System in with California until
some kind of equilibrium and balance is reached in California.
Again, thank you for this opportunity to testify. I would be happy
to respond to any questions you may have.
______
[Attachments to Ms. Scott's statement follow:]
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Mr. Calvert. I thank the gentlelady. Lastly, Mr. Richard
Erickson, you may begin your testimony.
STATEMENT OF RICHARD ERICKSON, SECRETARY/GENERAL MANAGER, EAST
COLUMBIA BASIN IRRIGATION DISTRICT
Mr. Erickson. Good afternoon, Mr. Chairman and members of
the Subcommittee. My name is Richard Erickson. I am the manager
of the East Columbia Basin Irrigation District. I would like to
thank you for the invitation to provide information about
Bonneville Power Administration's voluntary energy load
reduction program on the Columbia Basin Project. The Columbia
Basin Project was constructed by the Bureau of Reclamation and
is now primarily operated by the East, Quincy and South
Columbia Basin Irrigation Districts and provides irrigation
water to approximately 640,000 acres.
The first inkling of this energy program came on a January
31 phone call from Bonneville, asking if there would be any
possibility to make operational changes to bring about reduced
diversions from the Columbia River for the 2001 irrigation
season. BPA's purpose was to develop strategies to respond to
the developing energy and drought emergencies. The districts
were unable to offer much in the way of an encouraging response
because the project's canals are operated in direct response to
the irrigation delivery orders placed by individual farmers. In
other words, we only put into the canals what the farmers
order. Any operational tweaking would be truly minuscule in
terms of Columbia River flows. The only way to reduce
diversions would be to reduce water use by individual farmers
and since the project is already quite efficient both in terms
of on farm use and operationally, such a reduction could only
come about by idling acres.
Shortly thereafter Bonneville asked the three districts'
boards of directors to authorize discussions to attempt to
develop a voluntary land fallowing program for the project for
this summer. Prior to responding to this overture, the three
boards directed their attorneys and management to research any
potential adverse impacts of such a program to the balance and
interrelationships of project reservoirs and canals, to project
water rights, to project repayment contracts between
Reclamation and the districts, and also possible inadvertent
economic or social impacts to others. Based on generally
positive results to this research, the three boards authorized
negotiations, which began in earnest on February 14.
To understand the complexities of these negotiations
requires some discussion of plumbing. Irrigation water for the
project is pumped at Grand Coulee Dam into Banks Lake, which
normally has a lift of about 280 feet. Because of the drought
that lift is now about 370 feet. The energy for that pumping
lift is generated by other water falling through the turbines
at Grand Coulee. That falling water then is also used for
generation at Chief Joseph Dam and nine other dams downstream.
An acre-foot not pumped and then becoming available to generate
at Grand Coulee and Chief Joseph is equivalent to about one
megawatt-hour, not to mention the potential at the nine lower
dams. In normal times the wholesale value of that megawatt-hour
is $20 or less. This year that wholesale value at times has
ranged between $200 and $700. Each irrigated acre on the
project uses 3 to 4 acre-feet, equivalent to 3 or 4 megawatt-
hours. Until recently the crops grown by that irrigation
exceeded $1,000 per acre in average annual value, but that is
not true now, this year or in the past few years. Through the
course of these negotiations those numbers caused Bonneville to
offer project irrigators $330 per acre to not irrigate. That is
equivalent to $80 to $110 per megawatt-hour.
To further complicate these negotiations you have to
understand that the project's system is designed for the return
flows and spills from the upper two-thirds to supply the lower
two-thirds. Plus, the project canal system is the site of
several small hydroelectric plants having established power
purchase contracts with Seattle City Light, Tacoma Public
Utilities, and Grant County PUD. In view of current wholesale
energy prices, these contracts could not be shorted.
The program was opened for applications by irrigators on
March 19th. To bring this about, we had to develop contracts
for the districts to administer their program, contracts
between the individuals irrigators and Bonneville, letters of
consent between Reclamation and Bonneville, plus agreements
between the three canal system hydropower purchasers and
Bonneville. Also eligibility criteria were developed to attempt
to assure that participating acres would yield the energy
benefit being sought by Bonneville and to enable monitoring of
irrigators for contract compliance to be done in a reasonable
fashion.
All this was done knowing that February and March is the
start of the farming season in the Columbia Basin and being
late would assure no participation. The bulk of the
applications were received during the last 2 weeks of March and
the first week of April. The lateness of this time frame
created a lot of anxiety and frustration for farmers. However,
in most cases the time required from the initial application to
issuance of an approved contract was less than 2 weeks. 670
farmers have contracted with EPA to not irrigate 91,196 acres,
or about 15 percent of the project. Those acres should yield
something over 300,000 megawatt-hours of electricity this
summer.
My districts' board of directors asked me to emphasize two
points in conclusion. The first is that this year's unique
coincidence of very low crop values and an energy and crop
emergency, including very high wholesale energy costs, has
created a situation where agriculture and hydropower have been
able to help each other. This means some assured income in
uncertain times for participating farmers and some degree of
lower electric rates for thousands of northwest electric
ratepayers.
The second message is that these circumstances need to stay
unique and rare. Water transfers from agriculture should not be
seen as a substitute for constructing additional generating
capacity.
Thank you very much for the opportunity to present this
information and I would be happy to answer any questions.
[The prepared statement of Mr. Erickson follows:]
Statement of Richard L. Erickson, Secretary-Manager, East Columbia
Basin Irrigation District
Honorable Members of the Subcommittee on Water and Power:
Thank you for the invitation to provide information to the
Subcommittee about the opportunities and challenges of Bonneville Power
Administration's Voluntary Energy Load Reduction Program on the
Columbia Basin Project. The Columbia Basin Project, constructed by the
United States Bureau of Reclamation and now primarily operated by the
East, Quincy and South Columbia Basin Irrigation Districts presently
provides irrigation water to approximately 640,000 acres of farmland.
This irrigation is accomplished by diverting, at Grand Coulee Dam,
approximately 3% of the Columbia's flow. The Project is authorized by
Congress to ultimately irrigate 1,095,000 acres.
The first inkling of this energy load reduction program came in a
January 31st phone call from Bonneville to the CBP Irrigation
Districts' management asking if there would be any possibility for the
Districts to make operational changes to bring about reduced diversions
from the Columbia River at Grand Coulee Dam for the 2001 irrigation
season. BPA's stated purpose in this inquiry was to develop strategies
to respond to the developing energy and drought emergencies in the
Pacific Northwest. The Districts were unable to offer much in the way
of an encouraging response to this initial BPA request because the
CBP's extensive network of reservoirs and canals is operated in direct
response to irrigation delivery orders placed by individual farmers. In
other words Reclamation and the Districts only put into the canals what
the farmers ask for. Any operational tweaking of the system by the
Bureau of Reclamation or the Districts would be truly minuscule in
terms of Columbia River flows. It was suggested to BPA that the only
way to reduce CBP diversions would be to reduce water use by individual
farmers. Since the CBP is already very water efficient, both on-farm
and operationally, such a reduction could only come about by idling
acres. That initial discussion also included a recognition that the
present and prolonged downturn in crop values could possibly make the
temporary idling of some acres a serious consideration for some
farmers.
Shortly thereafter BPA asked the three Districts' Boards of
Directors to authorize discussions with BPA and Reclamation to attempt
to develop a voluntary CBP land fallowing program that would result in
an energy load reduction of irrigation pumping at Grand Coulee Dam plus
increased hydropower generation at both Grand Coulee and Chief Joseph
Dams. Prior to responding to this overture by BPA the three Boards
directed their attorneys and management to research any potential
adverse impacts of such a program to the balance and inter-
relationships of CBP reservoirs and canals, to CBP water rights, to CBP
repayment contracts between Reclamation and the Districts and also
possible inadvertent economic or social impacts to others. Among other
things this research concluded that USDA's Payment-In-Kind Program in
the early 1980's had idled over 70,000 CBP acres thus providing
something of a model and that Washington State water laws and CBP's
reclamation contracts provided sufficient flexibilities during
droughts. Research also estimated that effects on the balance of the
irrigation system and effects on others should be dispersed if the
idled acres were limited and dispersed. Based on this information the
three Boards, in conjunction with their own judgment that the
combination of depressed crop values and the developing power emergency
presented unique circumstances for irrigation and hydropower interests
to work together, authorized negotiations with BPA and Reclamation.
Negotiations in earnest began on February 14th.
To understand the value and complexities of these negotiations
requires some discussion of Columbia River and Columbia Basin Project
plumbing. Irrigation water for the CBP is pumped at Grand Coulee Dam
into Banks Lake, a lift of 280 feet normally. The present drought has
increased that lift to about 370 feet. The energy for that pumping lift
is generated by other water falling through the turbines at Grand
Coulee. That falling water then is used for generation at Chief Joseph
Dam and 9 other dams further downstream on the Columbia. An acre foot
not pumped to the CBP and then also becoming available to generate at
Grand Coulee and Chief Joseph Dams is equivalent to about 1 megawatt
hour, not to mention the potential at the 9 lower dams. In normal times
the wholesale value of that megawatt hour is $20 or less. This year
that wholesale value has, at times, ranged between $200 and $700. Each
irrigated acre on the CBP uses 3 to 4 acre feet, equivalent to about 3
or 4 megawatt hours. Until recently, the crops grown by that irrigation
exceeded $1000 per acre in average annual value. That is not true this
year or the past several years. Through the course of negotiations
those numbers caused BPA to offer CBP irrigators $330 per acre to not
irrigate, equivalent to $80 to $110 per megawatt hour. While well below
the $1000 per acre norm, this $330 turned out to be a good alternative
for lands slated for lower valued crops this year.
To further complicate negotiations and planning you have to
understand that CBP is designed for the return flows and spills from
the upper two-thirds of the Project to provide the water supply for the
lower one-third meaning the idled acres needed to be dispersed and
balanced. Plus, the CBP canal system is the site of 7 small
hydroelectric plants owned by the Districts having established power
purchase contracts with Seattle City Light, Tacoma Public Utilities and
Grant County PUD. In view of current wholesale energy prices, these
contracts could not be shorted.
The Voluntary Energy Load Reduction Program was opened for
applications by CBP irrigators on March 19th. To bring this about we
had to develop contracts for the Districts to administer the program
with the irrigators on behalf of BPA, also contracts between the
individual irrigators and BPA, letters of consent from Reclamation to
BPA plus agreements between the three canal system hydropower
purchasers and BPA. Also eligibility criteria were developed to attempt
to assure that participating acres would yield the energy benefit being
sought by Bonneville and to enable monitoring of irrigators for
contract compliance to be done in a reasonable fashion. All this was
done knowing that February and March is the start of the farming season
in the Columbia Basin and being late would assure no participation.
Bringing this from an initial phone call to implementation in 6 weeks,
considering it was being done by 2 federal agencies and 3 units of
local government plus involving 3 public utilities, especially
considering all the legal complexities, was done at light speed in
governmental terms. However, we'll probably have to wait until October
or later to definitively evaluate if it was done well, both for
agriculture and hydropower.
The bulk of the applications were received from interested farmers
during the last two weeks of March and first week of April. The
lateness of this time frame relative to the beginning of the growing
season created lots of anxiety and frustration for farmers. In most
cases the time required from the initial application by the farmer at
the District offices to issuance of an approved contract by BPA was
less than two weeks. All contacting was completed before the end of the
fifth week following the March 19th opening of the application process.
About 670 farmers have contracted with BPA to not irrigate about
91,196 acres, or about 15% of the Project. Those 91,196 acres should
yield something over 300,000 megawatt hours of electricity that
otherwise would probably have to be imported from outside the region at
a higher cost to BPA and its ratepayers. The participating acreage is
somewhat over the initial planning goal of 75,000 acres and the
original contracted goal of 83,888 acres. Also, the acreage did not
disperse quite as evenly as originally intended. Neither of those
factors is expected to be a major problem for the Project and could
only have been better orchestrated with the luxury of more time for
both planning and implementation.
The East District's Board of Directors has asked me to emphasize
two messages with this testimony. The first is that this year's unique
coincidence of very low crop values and an energy and drought
emergency, including very high wholesale energy costs, has created a
situation where agriculture and hydropower, respective rural and urban
interests, have been able to help each other. Meaning some assured
income in uncertain times for participating farmers and some degree of
lower electric rates for thousands of northwest electric ratepayers.
The second message is that these circumstances need to stay unique and
rare. Water transfers from agriculture should not be seen as a routine
or reliable source of energy or as a substitute for constructing
additional generating capacity. In normal times irrigation water should
be more valuable for producing food than electricity.
Again, thank you for this opportunity and for your consideration of
this testimony.
______
[Attachments to Mr. Erickson's statement follow:]
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Mr. Calvert. I thank the gentleman.
Mr. Feider, you mention in your testimony that the actual
kilowatt-hours produced by the CVP is not a good match for your
customer needs. Why is that?
Mr. Feider. As I also mentioned in my testimony, the
facilities at the Central Valley Project have outstanding
peaking capabilities and they were designed to do that to match
the overall needs in the State of California. However, they do
not produce the energy that matches the customer load, so that
is why it makes sense to purchase firming energy, as Western
presently does, from PG&E to maximize those benefits of the
project.
Mr. Calvert. What else can the Bureau do to expand kilowatt
production at the CVP?
Mr. Feider. As I also mentioned in my testimony, the
turbine upgrades that they have underway are certainly moving
in the right direction. There are two or three other power
plants that are under consideration right now, New Melones
Power Plant, Carr Power Plant and Spring Creek Power Plant,
that could also improve their efficiency and thus their output
could be improved.
Mr. Calvert. With those efficiencies and add on, what are
we talking about?
Mr. Feider. They are on the order of 5 or 6 percent in
additional generation. Every 1 percent helps in the current
situation.
Mr. Calvert. Do you have a megawatt number that you would
be--
Mr. Feider. Upgrades at Shasta Dam were about 50 megawatts
on the generator portion. The turbine portion that we are
looking forward to is about another 50 megawatts. The turbine
replacements at the other facilities I mentioned, I am not sure
if they will actually increase the capacity. They will mainly
increase the energy production.
Mr. Calvert. Can you explain the coordination with the
Federal Government when it comes to turbine and generated
replacement and upgrades? How are you coordinating on that? Is
it good or bad?
Mr. Feider. We have a fairly good working relationship with
the Bureau, where we have technical committees representative
of our communities such as Redding working with the Bureau's
technical people and evaluating proposals and helping run the
economics on those. So it has been a fairly well coordinated
effort over the last year or two. Prior to that perhaps it
wasn't as good as it needed to be.
Mr. Calvert. Could you please explain steps that could be
taken to have win/win, I guess if that is possible, on the
Trinity River Record of Decision regarding power.
Mr. Feider. On the public process last year the customers
of the CVP, particularly the power customers, put forth what we
think was a win/win proposal where you would increment parts of
improvements to the Trinity River operation in the short term.
We support the mechanical restoration of the riverbed by
mechanical means. We do not support using water every year to
try to maintain that riverbed. We would rather optimize mother
nature's gifts when she gives them to us in extreme water years
for that purpose. So we would also acknowledge that there may
be some need for additional water if the science justifies it
for temperature conditions, but for maintaining the riverbed
itself we think that is an inappropriate use of a valuable
resource.
Mr. Calvert. Why should the Federal Government be involved?
You mention the Path 15 issue when for many of you this is a
State problem. And obviously I am from California and we may
have a different perspective on that. But I hear that. Do you
think the Federal Government has a role in resolving that?
Mr. Feider. Yes, I believe the Federal Government has a
role. As I mentioned in my testimony, there are some what I
consider success stories where the Federal Government was
involved in the additions of 500,000 volt transmission lines.
The last two additions that were made in California in fact had
a role for the Federal Government. And we think that they have
existing authorities. We encourage the Department of Energy to
utilize those. We are in a situation where PG&E is not able to
move forward with construction, and from my perspective in the
California crisis whoever can build this project the fastest
ought to be building it.
Mr. Calvert. I am obviously in favor of getting this
bottleneck resolved as quickly as possible, but if in fact
Federal money is used for designed land acquisition and other
activities and putting that together, then I would presume
through Western--who should own and manage the transmission
line?
Mr. Feider. Well, the ownership answer could be worked out
over the next year or so and it could be a variety of parties.
It could be PG&E ultimately could have the ownership
transferred to them. It could be Western. If Western expends
Federal funds, we would expect those funds to be repaid through
user fees or comparable transmission capacity for optimizing
the Federal resource. The Transmission Agency of Northern
California, of which Redding is a member, also could be an
owner and is trying to facilitate those kind of arrangements as
well.
Mr. Calvert. Now is the design on Path 15 pretty much
completed? I mean, as far as land and design, is that pretty
much well known as far as being able to acquire that at a--
Mr. Feider. The actual status of the design I am not sure I
can speak to with a great degree of accuracy. What I can tell
you though is that project was identified back in the late
1980's and in fact was certified environmentally in 1988. So
there was a preliminary design at that time. The Transmission
Agency of Northern California has done some preliminary tower
siting and some preliminary design so I would say the design,
it is far enough along to begin the land acquisition process,
but certainly not to the extent of designing substation
termination facilities.
Mr. Calvert. How long will that take?
Mr. Feider. My belief is it can be done in a matter of a
few months, perhaps six at the most.
Mr. Calvert. Mr. DeFazio.
Mr. DeFazio. Thank you, Mr. Chairman. Ms. Scott, I think
there were some things in your testimony--I am sorry that Mr.
Otter left but perhaps I will get him to read the transcript
because I want to review a few of these points. I see the map
you have provided here and you do have member utilities
throughout the Northwest, including Idaho, is that correct?
Ms. Scott. Yes, that is correct. There is a membership map
also attached to the testimony.
Mr. DeFazio. Right, I saw that. We ask obvious questions
sometimes. But I look at this map and this is just the
Northwest and there is 40 congestion points on this map.
Ms. Scott. Yes, I think a few over 40.
Mr. DeFazio. As I read your testimony, you are saying 5 to
7 years to basically do major transmission, upgrades in many
cases where you have to do siting and things like that?
Ms. Scott. That is correct. By the time you go through the
whole process of planning, construction, environmental
requirements and the rating process, that is what all our
transmission engineers tell us, 5 to 7 years.
Mr. DeFazio. But let's say even optimistically somehow we
can have agreement, because some of these are already existing
lines. You already have right-of-way. There are not
particularly significant impacts in existing rights-of-way, et
cetera, if we were just at the point of probably 2 to 4 years,
then we could really speed up the process.
Ms. Scott. Yes, I think it is fair to say that it is a
whole different set of environmental impacts that you deal with
in upgrading transmission lines than, for example, generation.
Also there are multi-state jurisdictions on siting, so that
tends to slow things down a little bit.
Mr. DeFazio. Well, we will leave the years alone. I guess
what I am trying to get at here is in reading your testimony I
am very disturbed because what it seems to me where we might be
headed, and I have raised these concerns with BPA, is if we
superimposed a regional transmission organization which does
congestion management through a market mechanism, and I guess
markets are good for identifying problems and bringing about
efficiency but here we have already identified the problems, we
already know we are inefficient, what would likely be the
impact on transmission prices for your member utilities were we
to superimpose a mandate that we have transferable sellable
credits and go to a market base mechanism given these 40
congestion points in the Northwest.
Ms. Scott. I think Path 15, for example, was a good runner
up to this question. We know where the problems are and to a
large extent we know how extensive the problem is. If we relied
on a user-based--I say user-based because even if the RTO was
given the authority, it would use market mechanisms--but the
current proposal is to let this fall to individual users and it
relies on individual users experiencing high prices for a long
time. So to set up--
Mr. DeFazio. You mean during these 5 to 7 years the
market--every day the market would send me a signal that I was
on the wrong side of a transmission path constraint?
Ms. Scott. Exactly.
Mr. DeFazio. What could I do about it?
Ms. Scott. You could pay for it.
Mr. DeFazio. I could build generation on my side?
Ms. Scott. You could build generation on your side but most
of our loads in this area are on the Western, in the Valley
area or more to the Western side, and there is a reason why
generation isn't there. Generation has a pretty big footprint
in terms of air quality, land use, water use and noise. So
getting a generator sited is not a slam dunk proposal.
Also, load management is a possibility but again you need
to send a signal to consumers to make them willing not to use
electricity during critical periods. So alternatives to
transmission are available. They are not universally available
and as loads grow they become really marginal solutions.
Ultimately, you are going to have to fix some of these
transmission problems. Especially if Mr. Otter--well especially
in the Puget Sound area, for example, and the Portland area, at
some point there is only so much load management you can do.
And if you cannot get generation in you will have to do a
transmission fix. And leaving these to the market is I think
going to result in a market failure.
So instead of solving the problem we will continually
fracture into more and more congestion zones, which will
further disrupt the power markets.
Mr. DeFazio. So we kind of have the prospect if FERC rushes
to mandating a market based RTO we have the potential for
creating very similar problems to what we have in generation.
The Californians are getting a market signal every day that
they do not have enough generation, although there is a
question whether there is enough generation or there is market
manipulation. But it takes a while to build the generation. You
get the signal every day and you pay every day. So now we are
confronted with an even longer term prospect with the
transmission, of getting the signal every day, paying every day
and waiting until these things gets built.
Ms. Scott. That is correct, and I think in some ways we
would have many little Californias because as transmission
paths--
Mr. DeFazio. Now that is a scary thought, Mr. Chairman.
Mr. Calvert. Oregon is already a little California.
Ms. Scott. Because you would basically create little
islands of market power where the transmission is completely
constrained, and so whoever owned the rights or owned the
generation would have an enormous amount of market power and
the economic effect of that would be difficult. The currently
proposed system tends to shift this risk onto individual
utilities where now it is spread over a larger base, either
through Bonneville or through the jurisdictional ratemaking of
investor-owned utilities. Regardless of where a consumer is in
a State, currently we have statewide pricing for consumers.
Again, that is a little disconnect on the retail side from what
we are proposing on the wholesale side, I think similar to what
we had in California where we deregulated the wholesale side
but not the retail side.
Mr. DeFazio. If I could, Mr. Chairman, I mean as I
understood the original theory and I am interested in this and
how these theories go awry in application, but it is sort of
transmission would become a common carrier. And if I understand
that as a way to optimize the efficient use of our generation,
move power over longer distances and avoid having to build
generation here when you could match into another time zone or
into another season and another State, I understand those
things, but to get there we would need--and correct me if I am
wrong--it seems that your regional transmission organization
would need to be either as in the case of what was discussed
here earlier, the Federal Government perhaps intervening to
remove the congestion of Path 15, perhaps publicly owned or
owned by a nonprofit providing, the right-of-way, sort of like
our highways are today, for instance, at least in the West
where we don't have toll roads. And then, secondly, that this
organization seems to me would need to have the authority or
capability of either itself building or mandating the building
and the upgrading of the systems so we wouldn't have these
congestion points. And, third, and this hasn't been mentioned
and it wasn't mentioned in your testimony, it seems to me also
given what has gone on in California, it would need scheduling
authority if it is going to really assure reliability.
Of course that flies in the face of deregulation because
you certainly cannot tell someone who owns generation that they
should generate to keep the lights on and you will transmit it
someplace. But it seems to me if we wanted to optimize the
system those are the things we would do.
Ms. Scott. I agree with you on the first two points. You
know, we are not talking about not using a market base system
to do transmission expansion. We are only suggesting that a
different party have responsibility for that. So the RTO would
use a market system, for example, they would know where the
constraints were and they could say, market, I have a problem
here, what can you do for me. So people would bid in with
either transmission projects, generation projects, demand side
or whatever.
Mr. DeFazio. But you would not penalize people with higher
rates or cutting them up in the interim?
Ms. Scott. No.
Mr. DeFazio. You would go to the private sector or to the
market, whether it is public or private sector, and bid for
people to construct and upgrade.
Ms. Scott. Right, and by having the RTOs do it we could do
it in advance of need instead of waiting until it is a crisis
and then having to endure the high prices for 5 to 7 years. So
we would still be using a competitive market system but we
would be uplifting more of the costs across the system, not
necessarily the entire system, perhaps within a zone. As to the
scheduling authority, the RTO will have the ability to do
transmission scheduling but in terms of scheduling generation
that has not been envisioned. If the RTO were to relieve short-
term congestion it could use a redispatch system where it would
ask for incremental bids and decremental bids to turn
generation on or off on either side of a constraint or to get
load management on one side of a constraint as a short-term
tool.
So again that is a market based system for relieving the
congestion short term that I don't think is in --
Mr. DeFazio. But sort of in a controlled and regulated and
elegantly constructed market system. It is not the Wild West.
If I could, just one other point, Mr. Chairman. I have just
read there--I always get my Midwest States mixed up; Wisconsin
or Minnesota? Minnesota wants to access power that is now
coming from the West because of the deregulation in Montana
that Pennsylvania Power & Light, who is now operating all of
Montana's generations resources and wants to export to them,
they think in Minnesota they could get cheaper power that way.
But in the free market system that is prevailing there their
utilities want to build lines not to the West to access cheaper
power but lines to Chicago so they can ship their power to
Chicago where they think they can make more money. If we depend
upon the markets to dictate where and how we put transmission,
it does not seem that necessarily we will get solutions that
provide low cost power to consumers.
Ms. Scott. I think that is right. We forget that the
transmission system is a unified machine. And it is not--the
conditions for it to operate as a competitive market simply do
not exist, and I detail this very thoroughly in my paper. And I
think we need to remember RTO West is to optimize the power
market but transmission is still a monopoly and as such needs
to be operated a little differently.
Mr. DeFazio. Thank you, Mr. Chairman, for the extra time.
Mr. Calvert. I thank the gentleman. Ms. Scott, the five
established independent system operators, have they lived up to
expectations, in your opinion, in reducing congestion and
increasing reliability.
Ms. Scott. I guess in California we would have to say no.
Mr. Calvert. That is what I wanted to hear. How about the
other four?
Ms. Scott. I am not familiar with their operations, but I
do know they came from different backgrounds. In the East they
came from a tight power pool background, so they were already
operating and dispatching on a much different basis than we
operate out here. So I think they have been a little more
successful, but again they started from a different place.
Mr. Calvert. The 40 congestion points you mention in your
testimony, is there any common characteristic to those points;
are they different in some way?
Ms. Scott. Each one obviously is unique, but they all stem
from trying to move power from one side to load. Most of the
points--you know there is a lot of generation over on the east
side, a lot of coal plants, and many of these stem from moving
large amounts of coal fired generation in the East, Wyoming and
Montana, over to loads in the West. What is common about how
these operate is that power, for example, from the Bridger
plant, it spreads out and goes over 40 of these congestion
paths if you are trying to get a schedule into southern Oregon.
So you cannot just say it is here and it is going to go across
this way. It actually spreads out all over this system. A
schedule from Canada down to California spreads out over about
an equal number of paths. Some of the power actually flows
around to the East. So what is common is that the power flows
that we would be using in this new model is very diverse and if
we had to obtain rights on all the paths that we eventually
use, it could be an enormous set, thus giving the owner of even
a small amount of one of these lesser paths a degree of market
power.
Mr. Calvert. Under the RTO system how would the cost be
distributed among the users when building new transmission
lines? I guess that is the bottom line on the thing. How would
you do that, especially transmission between the two RTOs?
Ms. Scott. Which two RTOs? In California?
Mr. Calvert. And the Pacific Northwest. How would you do
that?
Ms. Scott. I would tell you how I would like to see it
done. The current proposal would have it fall to individual
users, but I don't think you are going to find people stepping
up for projects that have 5 to 7-lead times and 30 to 50-year
lives in an environment where people are requiring very short
paybacks and very high hurdle rates. So the way I would have it
done is I would have the RTO have very large zones with just a
few constraints and within the zones the RTO would fix the
congestion. It would then take the cost of that and spread it
to the users within a zone. There might have to be a different
treatment for through-flows, for flows that are for export, for
example.
Mr. Calvert. And this would apply to maintenance of the
system also?
Ms. Scott. You know, maintenance of the system is a fixed
cost, and that is right now going to be assigned to load. If
exports were treated as a load, then they would pick up their
fair share. The cost of this expansion would be some kind of
ongoing uplift for whatever period you needed to pay it back,
but presumably it would be less than the cost of clearing the
congestion in the short term. Otherwise you wouldn't fix it.
Mr. Calvert. Would you--and I apologize if I didn't hear
the number--the cost--you mentioned the time line but did you
mention a number on that again, the cost of fixing that
congestion problem?
Ms. Scott. No, I really wouldn't have any idea. Each one--
if you relieve some, then perhaps others are impacted. Some are
really big numbers and others are probably not, but I couldn't
tell you in total. I don't think anybody knows in total.
Mr. Calvert. I would assume it is a pretty good number.
Ms. Scott. I know Bonneville has asked for, I think, an
additional $750 million to undertake transmission upgrades on
its system alone.
Mr. Calvert. And this is obviously significantly more than
that.
Ms. Scott. I think you have to keep in mind 750 million is
a big number, but compared to what we have spent on power in
the past few months--
Mr. Calvert. We do that in 2 weeks in California.
Ms. Scott. Probably less.
Mr. Calvert. Are there any technical or regulatory barriers
that you need to overcome in order to create this RTO?
Ms. Scott. I'm sorry, technical or what?
Mr. Calvert. Technical and regulatory barriers-- you are
going to have to jump?
Ms. Scott. There are enormous both technical and regulatory
barriers.
Mr. Calvert. How many years did you think that that would
take?
Ms. Scott. Well, I think that realistically no one is
expecting the RTO to be in existence before late 2003. I think
that might be a little bit optimistic actually. We have to
create an entirely new scheduling center but, more importantly,
we have to put in place all the protocols for pricing,
planning, operations and congestion management. These things
don't exist. This would be brand new, brand new stuff.
Regulatorywise, there is an enormous problem, and that is that
the States have to approve each of the investor-owned utilities
participating in this. So we have not only FERC to get through
but also each State.
Mr. Calvert. In that case, you deal with a Federal judge
probably.
Ms. Scott. Well, we are hoping not to have to.
Mr. Calvert. Mr. Erickson, in general, how have many local
communities felt about the irrigation load back--or load
buyback program? How do they feel about that?
Mr. Erickson. I have attached some news articles in my
testimony that goes into that somewhat. Generally it was
popular with the farmers that wanted to participate just
because of the economic times they are in. There was a lot of
concern and criticism from some of the farm supply businesses
and also early on from some of the food processors about
secondary--secondary impacts on them. The food processors were
concerned that they would have sufficient acreage to supply
their raw product. Obviously fertilizer dealers, irrigation
supply dealers were concerned about a loss of business. The
perception, though, that I think a lot of them came to was
somehow that this money was going to Switzerland.
If you divide the 600 and some farmers that participated
into the 90,000 acres, that is like 150 acres per person that
participated. So they are all still farming. They just set
aside some land. So in effect I think the Bonneville money is
giving them some operating money. So I think most of that will
still find its way to a lot of the vendors that were concerned.
But it was--it was not without controversy, and it was a
consideration for our boards before they decided whether to go
ahead with it or not. But in the end they felt that in view of
the economic times, they could not deny the farmers of that
opportunity.
Mr. Calvert. Besides that buyback program, how has this
energy crisis affected agriculture in your area?
Mr. Erickson. I think it is expected to affect on onfarm
electric costs. The food processors, they are all indicating
that they are suffering higher electric costs, which is
squeezing them, again, on what they can offer to pay for raw
product. So I think it is going to affect rural communities
much the way it is the rest of the West.
Mr. Calvert. Any other questions?
Mr. DeFazio. If I could, Mr. Chairman, just back to Ms.
Scott. The part of the construct, again, that I am concerned
about that I understand that BPA and the other participating
utilities have put together is a system of firm transmission
rights and then auctioning off--those are fungible, as I
understand it, and also auctioning off any other surplus that
might exist in the system. And I am concerned about what that
might lead to. My understanding is, for instance, I have been
unable thus far to get details from BPA on this, that Morgan
Stanley--that rate utility has purchased 900 megawatts of
transmission in--out of BPA's system or leased 900 megawatts of
transmission and is giving the new--the new plant in Klamath
Falls a hard time about getting access, because I guess under
FERC rules--and you can correct me if I am wrong--they are sort
of limited in what they can recoup in terms of profit on
controlling the transmission, but they can deny anybody access
up until day of purchase short term. They can say--they don't
have to sell anybody firm rights; is that correct?
Ms. Scott. That is correct. I don't know about the Klamath
Falls plant. I do know they have made--I know of at least 600
megawatts that they have requested on the Intertie, and another
large amount at the Rathdrum project. I don't know if they are
involved with that or not, but they have an enormous request in
there. So they have the rights, and until you get into--after
the preschedule period, they don't need to release it. So--and
the same, incidentally, would be true in the RTO West system.
So--
Mr. DeFazio. Which would be--
Ms. Scott. Which would be if you had the FTR, the firm
transmission right, you don't need to release it until--you
don't ever need to release it, but the RTO will release it for
you if you don't use it at preschedule.
Mr. DeFazio. At what point, 1 hour, 1 day?
Ms. Scott. Preschedule is usually the day before, and the
preschedule period closes out usually 10 o'clock before the
active day.
Mr. DeFazio. So we could--with firm transmission rights, we
could be creating something similar to the California ISO spot
market purchase system?
Ms. Scott. Yes. I think that would be a little bit
different, but it would have the same potential for a kind of
chaos.
Mr. DeFazio. Thank you, I guess.
Thank you, Mr. Chairman.
Mr. Calvert. With that, I think I am going to thank the
panel, and we appreciate your coming out today and giving your
testimony and answering our questions. And this committee is
hereby adjourned.
[Whereupon, at 4:35 p.m., the Subcommittee was adjourned.]
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