[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








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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
                                 ------                                

                    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
                                ------                                










                            C O N T E N T S

                              ----------                              
                                                                   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

                              ----------                              


                        Thursday, April 26, 2001

                     U.S. House of Representatives

                    Subcommittee on Water and Power

                         Committee on Resources

                             Washington, DC

                              ----------                              

    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.
                                 ______
                                 

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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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