[Senate Hearing 112-63]
[From the U.S. Government Publishing Office]
S. Hrg. 112-63
WATER AND POWER BILLS
=======================================================================
HEARING
before the
SUBCOMMITTEE ON WATER AND POWER
of the
COMMITTEE ON
ENERGY AND NATURAL RESOURCES
UNITED STATES SENATE
ONE HUNDRED TWELFTH CONGRESS
FIRST SESSION
ON
S. 201 S. 333
S. 334 S. 419
S. 499 S. 519
S. 808
__________
MAY 19, 2011
Printed for the use of the
Committee on Energy and Natural Resources
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COMMITTEE ON ENERGY AND NATURAL RESOURCES
JEFF BINGAMAN, New Mexico, Chairman
RON WYDEN, Oregon LISA MURKOWSKI, Alaska
TIM JOHNSON, South Dakota JOHN BARRASSO, Wyoming
MARY L. LANDRIEU, Louisiana JAMES E. RISCH, Idaho
MARIA CANTWELL, Washington MIKE LEE, Utah
BERNARD SANDERS, Vermont RAND PAUL, Kentucky
DEBBIE STABENOW, Michigan DANIEL COATS, Indiana
MARK UDALL, Colorado ROB PORTMAN, Ohio
JEANNE SHAHEEN, New Hampshire JOHN HOEVEN, North Dakota
AL FRANKEN, Minnesota BOB CORKER, Tennessee
JOE MANCHIN, III, West Virginia
CHRISTOPHER A. COONS, Delaware
Robert M. Simon, Staff Director
Sam E. Fowler, Chief Counsel
McKie Campbell, Republican Staff Director
Karen K. Billups, Republican Chief Counsel
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Subcommittee on Water and Power
JEANNE SHAHEEN, New Hampshire, Chairman
RON WYDEN, Oregon MIKE LEE, Utah, Ranking
TIM JOHNSON, South Dakota JAMES E. RISCH, Idaho
MARIA CANTWELL, Washington DANIEL COATS, Indiana
BERNARD SANDERS, Vermont JOHN HOEVEN, North Dakota
DEBBIE STABENOW, Michigan BOB CORKER, Tennessee
JOE MANCHIN, III, West Virginia
Jeff Bingaman and Lisa Murkowski are Ex Officio Members of the
Subcommittee
C O N T E N T S
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STATEMENTS
Page
Lee, Hon. Mike, U.S. Senator From Utah........................... 2
Moe, Darrick, Regional Manager of the Desert Southwest Region,
Western Area Power Administration, Department of Energy........ 10
Murillo, David, Deputy Commissioner, Operations, Bureau of
Reclamation, Department of the Interior........................ 3
Shaheen, Hon. Jeanne, U.S. Senator From New Hampshire............ 1
APPENDIXES
Appendix I
Responses to additional questions................................ 23
Appendix II
Additional material submitted for the record..................... 27
WATER AND POWER BILLS
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THURSDAY, MAY 19, 2011
U.S. Senate,
Subcommittee on Water and Power,
Committee on Energy and Natural Resources,
Washington, DC.
The subcommittee met, pursuant to notice, at 2:41 p.m. in
room SD-366, Dirksen Senate Office Building, Hon. Jeanne
Shaheen presiding.
OPENING STATEMENT OF HON. JEANNE SHAHEEN, U.S. SENATOR FROM NEW
HAMPSHIRE
Senator Shaheen. Good afternoon. I want to call this
hearing to order, of the, the first hearing for this year of
the Water and Power Subcommittee. Welcome everyone. I apologize
for being late. As you know, we had a vote, and obviously,
Senator Lee is a lot faster than I am.
Senator Lee is our ranking member, and I look forward to
working with him on the subcommittee. As I said to him, many of
the, particularly the bills that we're going to be hearing
today, affect the West much more than the East, so his
perspective will be very important.
Today's hearing involves 7 bills that are pending before
the subcommittee. The bills cover several different aspects of
our water and power jurisdiction. We held hearings on these
bills or similar bills during the 111th Congress, and we're
looking forward to addressing them during this Congress as
well.
We're only hearing today from administration witnesses.
We've already received statements for the record on some of
these bills, and we will leave the record open for 2 weeks in
order to receive additional statements.
The bills we're covering today are S. 201, a bill to
clarify the jurisdiction of the Secretary of the Interior with
respect to the C.C. Cragin Dam and Reservoir, and for other
purposes; S. 333, a bill to reinstate and extend the deadline
for commencement of construction of a hydroelectric project
involving the Little Wood River Ranch in Idaho; S. 334, a bill
to reinstate and extend the deadline for commencement of
construction of a hydroelectric project involving the American
Falls Reservoir in Idaho; S. 419, the Dry Red Water Regional
Water Authority System Act of 2011, to authorize a drinking
water project in rural Montana and North Dakota; S. 499, the
Bonneville Unit Clean Hydropower Facilitation Act, to
restructure the repayment obligation for a portion of the
central Utah project; S. 519, the Hoover Power Allocation Act
of 2011, to reauthorize the contracts relating to hydroelectric
power generated at Hoover Dam in Nevada for the benefit of
power users in Nevada, Arizona and California; and S. 808, a
bill to direct the Secretary of the Interior to allow for
prepayment of the repayment amounts owed to the United States
by the Uintah Water Conservancy District, and for other
purposes.
At this point I'd like to turn to Senator Lee in case he
has any opening remarks.
STATEMENT OF HON. MIKE LEE, U.S. SENATOR FROM UTAH
Senator Lee. Thank you, Senator Shaheen. Thanks for
chairing this hearing and for letting me serve on this
subcommittee with you. I look forward to working on these
issues.
Two of the issues we'll be discussing today affect my home
State--S. 499, the Bonneville Unit Clean Hydropower
Facilitation Act, and S. 808, a bill to allow for prepayment of
contracts between the United States and the Uintah Water
Conservancy District. I've cosponsored both of these pieces of
legalization with my friend and fellow Utahan, Senator Hatch.
All of these issues here before us today address many of
the issues we'll be examining over the next couple of years,
and these includes things like mechanisms to provide safe and
reliable water services to rural communities, different
approaches to resolve jurisdictional issues among competing
Federal agencies to avoid duplication of efforts, and
opportunities to improve our power supplies. So, while the
underlying purpose of each specific bill before us today may be
different, they all attempt to identify tools that will help
ensure that our water and power facilities are safe and
reliable, and operating properly.
I thank the Federal witnesses for their presence here
today.
I thank you, Senator Shaheen, for conducting this hearing.
I look forward to the testimony we'll receive.
Senator Shaheen. Thank you, Senator Lee.
We'll now move to our testimony from the 2 witnesses.
The first witnesses, witness is David Murillo, the Deputy
Commissioner for Operations from the Bureau of Reclamation.
He'll provide testimony relating to S. 201, S. 429, S. 499, and
S. 808.
The second witness will be Darrick Moe, the Regional
Manager of the Desert Southwest Region of the Western Area
Power Administration. Mr. Moe will testify regarding S. 519.
So, welcome to both of you.
I would also just point out that we've received testimony
for the record from the Federal Energy Regulatory Commission
regarding S. 333 and S. 334, and we will enter that into the
record.
[The prepared statement of Senator Baucus follows:]
Prepared Statement of Hon. Max Baucus, U.S. Senator From Montana,
on S. 419
Madam Chair and members of the subcommittee, thank you for the
opportunity to provide testimony to the subcommittee in support of
Senate Bill 419, the Dry-Redwater Regional Water Authority System Act
of 2011. This bill would bring clean drinking water to communities in
east central Montana. It authorizes funding for construction of the
Dry-Redwater municipal water project in Dawson, Garfield, Prairie, and
Richland Counties, which will bring clean water to thousands of Montana
families and support jobs through long-term economic development.
Water is critical to every community. This bill would at last
resolve water treatment challenges that have harmed the health and
pocketbooks of eastern Montanans. All Americans deserve safe, clean
drinking water for their families, their ranches and farms, and their
businesses.
Communities in Dawson, Garfield, Prairie, and Richland counties
have problems accessing clean water with the current water system,
which not only poses a health risk to residents but also stains sinks,
destroys faucets and hinders new business and jobs to the area. Five
central water treatment facilities currently address high fluoride,
sodium, organics, and total dissolved solid levels in the raw
groundwater. Centralizing treatment in a single regional facility will
resolve persistently elevated pollutant levels in the current system,
reduce long-term costs through economies of scale, eliminate wastewater
storage problems at existing facilities, and shield municipalities from
fluctuating user bases as populations shift. When completed, the Dry-
Redwater Project would provide clean, reliable water for thousands of
families in east central Montana.
I plan to work with the Bureau of Reclamation (Reclamation) to
resolve several issues that remain outstanding in this introduced
legislation. In particular, I am pleased that progress is being made on
completing a feasibility study to address the concerns of Reclamation
with respect to complying with criteria in the Rural Water Supply Act
of 2006. I urge participants in this study to double-down their efforts
in order to move quickly toward verifying the cost estimates of the
project in a feasibility report. The current legislation authorizes
funding contingent on a finding by the Secretary of the Interior of the
project's feasibility. This contingent authorization is similar in
structure to other rural water projects and reflects initial completion
of the proposal prior to finalization of criteria under the Rural Water
Supply Act of 2006.
I stress the need to move forward on the Dry-Redwater project given
the nine years that east central Montana has invested in its fruition.
Thank you.
Senator Shaheen. So, Mr. Murillo, if you would like to
begin, and maybe we can ask you to summarize your testimony so
we can keep it within about a 5-minute period.
STATEMENT OF DAVID MURILLO, DEPUTY COMMISSIONER, OPERATIONS,
BUREAU OF RECLAMATION, DEPARTMENT OF THE INTERIOR
Mr. Murillo. All right. I'll try to go quickly through
this.
Senator Shaheen. Oh, I'm sorry.
Mr. Murillo. That's OK.
Senator Shaheen. I'm reminded that you're, because you're
testifying on a number of those pieces of legislation, you
should feel free to take more than 5 minutes, and take the full
10 minutes.
Mr. Murillo. You already asked a touch question to begin
with 5 minutes, so, now I get 10. Thank you.
Madame Chairwoman, and members of the subcommittee, I am
David Murillo, Deputy Commissioner of Operations at the Bureau
of Reclamation. I am pleased to provide the views of the
Department of the Interior on 4 bills before the subcommittee
today--S. 201, S. 419, S. 499, and S. 808.
With me today is Robert Cunningham, Assistant Director of
Lands at the U.S. Forest Service, who's prepared to respond to
any technical questions the subcommittee may have on S. 201.
My written statements have been submitted for the record.
[The prepared statements of Mr. Murillo follow:]
Prepared Statements of David Murillo, Deputy Commissioner, Operations,
Bureau of Reclamation, Department of the Interior,
on s. 499
Madam Chairwoman and members of the Committee, I am David Murillo,
Deputy Commissioner for Operations of the Bureau of Reclamation. I am
pleased to be here today on behalf of the Assistant Secretary for Water
and Science who oversees the Central Utah Project Completion Act
activities to present the Administration's views on S. 499, the
Bonneville Unit Clean Hydropower Facilitation Act. The proposed
legislation is associated with development of hydropower on the Diamond
Fork System, Bonneville Unit, Central Utah Project.
The Central Utah Project Completion Act (CUPCA) provides for the
completion of the construction of the Central Utah Project (CUP) by the
Central Utah Water Conservancy District (CUWCD). CUPCA also authorizes
programs for fish, wildlife, and recreation mitigation and
conservation; establishes an account in the Treasury for deposit of
appropriations and other contributions; establishes the Utah
Reclamation Mitigation and Conservation Commission to coordinate
mitigation and conservation activities; and provides for the Ute Indian
Water Rights Settlement.
Hydropower development on CUP facilities was authorized as part of
the Colorado River Storage Project Act (CRSPA) under which the Central
Utah Project is a participating project. The development of hydropower
on the Diamond Fork System has been contemplated since the early days
of the CUP. The 1984 Environmental Impact Statement on the Diamond Fork
System described the construction of five hydropower plants with a
combined capacity of 166 MW of power.
However, these hydropower plants were never constructed and the
1999 Environmental Impact Statement on the Diamond Fork System
presented a plan which specifically excluded the development of
hydropower, stating ``there are no definite plans or designs, and it is
not known if or by whom they may be developed.''
Although hydropower development was not included, construction of
pipelines and tunnels for the Diamond Fork System were completed and
put into operation in July 2004. Under full operation the Diamond Fork
System will annually convey 101,900 acre-feet of CUP Water and 61,500
acre-feet for Strawberry Valley Project water users.
In 2002 CUPCA was amended to authorize development of federal
project power on CUP facilities. With this new amendment plans for
hydropower development at Diamond Fork were included in the 2004 Utah
Lake System Environmental Impact Statement and the 2004 Supplement to
the Definite Plan Report for the Bonneville Unit (DPR). These documents
describe the construction of two hydropower plants on the existing
Diamond Fork System for a total generating capacity of 50 MW.
Section 208 of CUPCA included provisions that power on CUP features
would be developed and operated in accordance with CRSPA and CUP water
diverted out of the Colorado River Basin for power purposes would be
incidental to other project purposes.
There are two options for hydropower development on the Diamond
Fork System: 1) federal project development or 2) private development
under a Lease of Power Privilege contract with the United States.
Under the first option the CUWCD would construct the Diamond Fork
hydropower plants under contract with the United States and contribute
an up front local cost share of 35 percent of the construction costs.
In addition to the hydropower plant construction costs, the costs of
conveyance facilities upstream of Diamond Fork System that are
allocated to power would have to be repaid. The DPR allocates costs of
the CUP according to project purposes. The reimbursable costs allocated
to power are $161 million based upon the costs of developed features
upstream of the Diamond Fork System. It is anticipated that under this
option, these allocated costs would be repaid through an arrangement
among Interior, CUWCD, and the Western Area Power Administration
(WAPA).
Under the second option, private hydropower could be developed.
Although the DPR and 1999 EIS describe federal hydropower development,
they also provide the option for a Lease of Power Privilege arrangement
with the United States. Under this arrangement Interior would implement
a competitive process to select a lessee for private development of
hydropower at Diamond Fork. The lease arrangement would require
repayment of the $161 million of upstream costs plus annual payments to
the United States for the use of the federal facilities, amounting to
at least a 3 mil rate paid by the lessee to the United States.
S. 499 does not preclude federal development of hydropower, but it
does increase the likelihood of private development. If enacted, this
bill would indefinitely defer the $161 million in costs allocated to
power development in the Diamond Fork System under section 211 of
CUPCA, thus reducing the cost of hydropower development at this site.
This bill would increase the likelihood that a private developer would
pursue a Lease of Power Privilege arrangement because the private
developer would not, under this legislation, be required to repay the
$161 million of construction costs that were allocated to power as
would be required under existing law.
We understand and appreciate the goal of this legislation of
facilitating the development of hydroelectric power on the Diamond Fork
System.
However, the Administration has serious concerns about losing our
ability to recoup the Federal investment made in these facilities as
set forth in this legislation. The Federal government may benefit in
the medium term from the annual payments for the use of Federal
facilities that would be paid if a lessee entered into a Lease of Power
Privilege arrangement for production of hydroelectric power on the
Diamond Fork System. Assuming only a summer water supply as under
current deliveries, these payments are estimated at about $400,000 a
year starting the year that the project is completed and continuing for
the life of the project. However, because payment of $161 million of
allocated power costs would be postponed indefinitely, it is unclear
what the long-term fiscal implications of enactment of this legislation
would be and how the United States Treasury would be made whole. This
legislation would potentially permanently postpone anticipated receipts
to the U.S. Treasury at the expense of the Federal taxpayer. While it
is not clear at this time whether a nonfederal developer would propose
a hydroelectric project at Diamond Fork under current law, if this were
to occur, repayment of the allocated power costs would begin after the
hydroelectric project is completed and average $5.3 million a year for
50 years.
Section 5 of S. 499 would prohibit the use of tax-exempt financing
to develop any facility for the generation or transmission of
hydroelectric power on the Diamond Fork System. This provision was
added to the bill to prevent any loss of revenue to the federal
government as a result of the financing mechanism used for development
of hydropower at this site.
on s. 808
Madam Chairman and Members of the Subcommittee, I am David Murillo,
Deputy Commissioner of Operations of the Bureau of Reclamation
(Reclamation). Thank you for the opportunity to provide the views of
the Department of the Interior (Department) on S. 808, as introduced on
April 13, 2011. This legislation allows for prepayment of the current
and future repayment contract obligations of the Uintah Water
Conservancy District (District) of the costs allocated to their
municipal and industrial water (M&I) supply on the Jensen Unit of the
Central Utah Project (CUP) and provides that the prepayment must result
in the United States recovering the net present value of all repayment
streams that would have been payable to the United States if S. 808
were not enacted. S. 808 would amend current law to change the date of
repayment to 2022 from 2037. The legislation would also allow repayment
to be provided in several installments and requires that the repayment
be adjusted to conform to a final cost allocation. The Department
supports S. 808.
The District entered into a repayment contract dated June 3, 1976,
in which they agreed to repay all reimbursable costs associated with
the Jensen Unit of the CUP. The Jensen Unit's total water supply was
envisioned at this time to be roughly 18,000 acre-feet because plans
anticipated completion of another pumping plant at a location on the
Green River known as Burns Bench.
However, for a variety of reasons, the Burns Bench feature was
never built. And with the enactment of language in Section 203(g) of
the Central Utah Project Completion Act of 1992 (P.L. 102-575), the
District's contract was amended in 1992 to reduce the project M&I
supply subject to repayment to 2,000 acre-feet annually, and
temporarily fix repayment for this supply based upon a reduced interim
cost allocation developed for the still-uncompleted project. The
amended 1992 contract required the District to repay about $5.545
million through the year 2037 at the project interest rate of 3.222%
with annual payments of $226,585. The current balance due, without
discounting, is $3,949,058 as of 2011.
It is important to note that this $3,949,058 figure reflects a
repayment amount that is statutorily lowered by the 1992 legislation,
and does not reflect the true repayment costs of the Jensen Unit. The
costs allocated to the 2,000 acre-feet of contracted M&I supply, and
the M&I supply available through additional incomplete project
features, may be significantly revised upward in the future upon
project completion or enactment of this bill, both of which would
require a Final Cost Allocation. An additional currently unallocated
cost of $7,419,513 is expected to be allocated to the contracted 2,000
acre-feet in order to achieve a full and final project repayment.\1\
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\1\ This allocation will be subject to revision should there be
additions to the project.
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These are the costs that paragraph 3 of S. 808 requires to be
included in the prepayment. The 2011 balance on the 1992 M&I repayment
contract is $3,949,058 and the adjustment amount when factoring in the
total project cost including interest on that debt is $7,419,513.
Therefore, in total non-discounted dollars, the Conservancy District
owes the Federal government $11,368,571.
Under Reclamation law, water districts are not authorized to prepay
their M&I repayment obligation based upon a discounted value of their
remaining annual payments.
This legislation would authorize early repayment by the Uintah
Conservancy District to the Federal government. Because there is an
interest component to the M&I repayment streams to be repaid early,
early repayment without an adjustment for interest would result in
lower overall repayment to the United States. To keep the United States
whole, the Bureau of Reclamation would collect the present value of the
whole amount that would be due without early repayment.
The language in S. 808 has been amended from the language contained
in an earlier version of this legislation, S. 1757 (111th Congress).
The amended language clarifies that this legislation requires that the
Federal government be paid what it is owed by the Conservancy District.
Because the United States supports the goals of providing for early
repayment under this contract so long as the United States is kept
whole, and S. 808 clearly establishes that early repayment under this
legislation must be of an amount equal to the net present value of the
foregone revenue stream, the Department supports this legislation.
on s. 201
Madam Chairman and Members of the Subcommittee, I am David Murillo,
Deputy Commissioner of Operations of the Bureau of Reclamation
(Reclamation). Thank you for the opportunity to provide the views of
the U.S. Department of the Interior (Department) on S. 201, legislation
specific to lands underlying the C.C. Cragin Dam, Reservoir and utility
corridor (C.C. Cragin project) in Arizona. The legislation seeks to
clarify federal jurisdiction with respect to the C.C. Cragin project,
which includes a dam, reservoir, and 11.5-mile utility corridor
containing a transmission line and high-pressure pipeline. The project
is located nearly entirely within the Coconino National Forest in
north-central Arizona.
Language included in the Arizona Water Settlements Act (AWSA,
Public Law 108-451) created questions about the respective jurisdiction
of the U.S. Forest Service (Forest Service) and Reclamation related to
the C.C. Cragin project. We have come to an agreement that we think can
resolve this issue. This legislation is consistent with that
arrangement. We look forward to continue working with the Committee on
reaching a resolution.
Reclamation and the Forest Service worked closely with the Salt
River Project Agricultural Improvement and Power District (SRP), the
entity that operates and maintains the C.C. Cragin project under the
AWSA, and reached agreement in mid-2010 on legislation to clarify
jurisdiction of the Federal agencies. The legislation, S. 1080, was
considered during the 2nd session of the 111th Congress. The bill was
not enacted during the last Congress, but both S. 201 and its companion
bill, H.R. 489, contain the same provisions as S. 1080, as reported.
This legislation accommodates the needs of Reclamation and SRP by
ceding exclusive administrative jurisdiction over the lands underlying
the C.C. Cragin project to Reclamation and by expressly acknowledging
SRP's responsibility for operating and maintaining the C.C. Cragin
project pursuant to the AWSA and the 1917 agreement between the
Department and SRP. This is a unique situation due to the AWSA. In
addition, this approach accommodates the Forest Service by allowing the
agency to manage the lands underlying the utility corridor with respect
to recreation, wildfire, law enforcement, and other activities
consistent with the Forest Service's authorities, responsibilities, and
expertise; the AWSA; the 1917 agreement; and the existing right-of-way
over the utility corridor held by another party. This approach would
allow for integrated management of tens of thousands of acres of
ecosystems across National Forest System lands underlying and adjacent
to the C.C. Cragin project, including watershed, wildlife habitat,
range, and vegetation management. S. 201 allows for a workable
agreement for both day-to-day activities and other activities that will
improve the management and safety of the covered land. The
Administration believes that this legislation provides a sound approach
for future management of the C.C. Cragin project. Both Reclamation and
the Forest Service are committed to working diligently with SRP to
ensure needed work for the C.C. Cragin project can be accomplished
expeditiously, including any necessary emergency and non-emergency
repairs and replacement of improvements, in full compliance with
applicable law, including the National Environmental Policy Act and the
Endangered Species Act, as provided in the AWSA.
Reclamation's long-standing experience working with SRP over nearly
a century has been very productive. SRP has proven to be a responsible
and reliable operator and caretaker of U.S. interests and resources.
Reclamation and SRP have nearly a century of responsible stewardship in
regard to both the technical operation of dams and reservoirs and
protection of natural resources. It is our hope that combining that
history with the Forest Service's land management authorities and
expertise would result in even more effective stewardship.
on s. 419
Madam Chairman and Members of the Subcommittee, I am David Murillo,
Deputy Commissioner for Operations at the Bureau of Reclamation
(Reclamation). I am pleased to provide the views of the Department of
the Interior (Department) on S. 419, legislation authorizing
construction of the Dry-Redwater Regional Water Authority System
(System) in the State of Montana. We recognize that changes have been
made to the language of this bill since the last Congress, however, the
Administration still has concerns with this bill that we want to work
with Congress to address.
S. 419 would authorize the planning, design, and construction of
the System in eastern Montana and would authorize appropriations of at
least $115 million for the System. The bill would require that the
Federal government provide up to 75 percent of the project's overall
cost.
The Department concurs in the need for a safe and reliable water
supply for the citizens of eastern Montana, and earlier this year,
Reclamation began providing financial assistance to complete a
feasibility study of this project in accordance with Title I of the
Rural Water Supply Act of 2006 (Public Law 109-451), as described
below. However, we have concerns with the legislation as currently
written. In particular, the Department is concerned about the process
issues raised by this legislation authorizing a project for
construction before the feasibility study is complete even while other
rural water projects are being studied, the potential strain on
Reclamation's budget that could come about from this authorization, the
cost share requirement proposed in the bill, and the proposed use of
power from the Pick-Sloan Missouri Basin Program (P-SMBP) for non-
irrigation purposes.
Of Reclamation's seven currently authorized rural water projects
being constructed or funded at some level today, five are in
Reclamation's Great Plains (GP) region and are currently being
constructed in the Dakotas and Montana.\1\ All of these projects pre-
date Public Law 109-451, which authorized the Secretary of the Interior
to create a rural water supply program to address rural water needs in
the 17 western States. Within the GP region, more than 224,926 people
are presently being served by the six partially completed projects
(approximately 45,860 on Indian reservations and 179,066 off
reservations). The fiscal year (FY) 2012 rural water project request
was $35.5 million. This includes $15.3 million for the operation and
maintenance of tribal systems and $20.2 million for construction. In
addition, the American Recovery and Reinvestment Act of 2009 provided
approximately $232 million to these rural water projects. The remaining
construction ceiling for these six projects totals approximately $1
billion. The Department of the Interior (Bureau of Reclamation)
prioritizes funding for these ongoing authorized projects based on (1)
the required O&M component; (2) projects nearest completion; and (3)
projects that serve on-reservation needs.
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\1\ Mni Wiconi Project (SD), PSMB/Garrison Diversion Project (ND),
Forest Peck Reservation/Dry Prairie Rural Water System (MT), Rocky
Boy's/North Central
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In view of these existing authorizations, the Department is
concerned about the non-Federal cost share for the System. S. 419
contemplates that the United States would fund 75 percent of the cost
of constructing the System for the benefit of Montana citizens of
Dawson, Garfield, McCone, Prairie, and Richland Counties, and North
Dakota citizens of McKenzie County. While this has been the cost share
level proposed in other rural water projects enacted into law, it
represents the very maximum Federal cost share allowed under the Rural
Water Supply Act of 2006, which includes a requirement for a
Feasibility Report that includes an analysis of the sponsor's
capability-to-pay and identifies an appropriate contribution by the
local sponsors.
The Dry-Redwater Regional Water Authority (Authority) prepared a
study that was accepted by Reclamation as an appraisal study in June
2010. The Authority then submitted a proposal to Reclamation for
financial assistance to complete a feasibility study in accordance with
Title I of the Rural Water Supply Act of 2006. Reclamation approved the
request and provided cost-share funding in the amount of $120,500 in
direct contributions. Reclamation also agreed to provide technical
assistance valued at $119,500 using its own resources, resulting in a
total Federal contribution of $240,000, which is 50 percent of the
total study cost of $480,000. This cooperative agreement was executed
in January 2011 and the feasibility study is scheduled for completion
in September 2012. Reclamation will continue to work with the Authority
to prepare the feasibility study and prepare a feasibility report to
verify the accuracy of the cost estimates and provide information on
what the sponsor's capability-to-pay would be which helps determine the
appropriate non-Federal cost share.
Section 5 of S. 419 authorizes the delivery of 1.5 megawatts P-SMBP
pumping power to be used and delivered between May 1 and October 31 for
the benefit of this System at the firm power rate. Section 5(b)(2) of
the bill requires that the System be operated on a ``not-for-profit
basis'' in order to be eligible to receive power under those terms.
Reclamation is not certain of the impact the bill's requirements could
have on Western Area Power Administration's existing contractual power
obligations.
In addition to those concerns mentioned above, we have yet to
verify whether or not water rights issues associated with the System
have been adequately addressed. Without an opportunity to thoroughly
review the proposed System at feasibility study level, we are not in a
position to verify that other technical issues do not also exist. We
would like to suggest that the System sponsors continue working with
Reclamation's GP Regional Office and the Montana Area Office to
complete feasibility-level studies consistent with the Rural Water
Supply Act of 2006.
That concludes my statement. I am pleased to answer any questions.
Mr. Murillo. S. 201 seeks to clarify Federal jurisdiction
with respect to the C.C. Cragin project, which includes a dam,
reservoir, and an 11.5-mile utility corridor containing a
transmission line and high pressure pipeline. The project is
located nearly entirely within the Coconino National Forest in
north-central Arizona.
Language included in the Arizona Water Settlement Act
created questions about the respective jurisdictions of the
Forest Service and the Bureau of Reclamation related to the
C.C. Cragin project. Our agencies have come to an agreement
that we think can resolve this issue, and this legislation is
consistent with that arrangement.
Reclamation and the Forest Service worked closely with the
Salt River Project, or SRP, which operates and maintains the
C.C. Cragin project, and reached agreement in May 2010 on the
terms for managing the project. This legislation accommodates
the needs of Reclamation and SRP by ceding administrative
jurisdiction over the lands underlying the dam and reservoir to
Reclamation, and by expressly acknowledging SRP's
responsibility for operating and maintaining the dam, reservoir
and utility corridor.
In addition, this approach accommodates the Forest Service
by allowing the agency to manage the lands underlying the
utility corridor for recreation, wildfire, law enforcement, and
other activities.
The Administration believes that this legislation provides
a sound approach for future management of the project.
Both departments are committed to work diligently with SRP
to ensure needed work for the project can be accomplished
expeditiously.
Reclamation's long-standing experience with SRP over nearly
a century has been positive and very productive. It is our hope
that combining that history with the Forest Service land
management authorities and expertise will result in even more
effective stewardship.
S. 419, Dry-Redwater. S. 419 would authorize the planning,
design, and construction of the Dry-Redwater Regional Water
Authority System in eastern Montana and authorize
appropriations of $115 million for the system. The bill would
require that the Federal Government provide up to 75 percent of
the project's overall cost.
The Department recognizes the needs for a safe and reliable
water supply for the citizens of eastern Montana, and earlier
this year Reclamation began providing financial assistance to
complete a feasibility study of this project in accordance with
the Rural Water Act--Rural Water Supply Act of 2006.
However, we are concerned about the process issues raised
by this legislation, which authorizes the project for
construction before the feasibility study is complete. The bill
poses a potential strain on Reclamation's budget that could
come about from enactment.
The Dry-Redwater Authority prepared a study that was
accepted by Reclamation as an appraisal study in June 2010. The
authority then submitted a proposal to Reclamation for
financial assistance to complete a feasibility study in
accordance with the Rural Water Act. Reclamation approved the
request and provided cost-sharing funding in the amount of
$120,500 in direct contributions. Reclamation also agreed to
provide technical assistance valued at $119,500, using its own
resources, resulting in a total Federal contribution of
$240,000, which is 50 percent of the total study cost of
$480,000. This cooperative agreement was executed in January
2011, and a feasibility study is scheduled for completion in
September 2012.
Reclamation will continue to work with the Authority to
prepare the feasibility study and determine the appropriate
non-Federal cost share. We would like to suggest that the
system sponsors continue working with Reclamation's Great
Plains Regional Office and the Montana Area Office to complete
the feasibility study, consistent with the Rural Water Supply
Act of 2006.
S. 499, Diamond Fork. S. 499 would facilitate the
development of hydropower on the Diamond Fork System of the
Central Utah Project pursuant to the Central Utah Project
Completion Act, or CUPCA.
The provisions of S. 499 increase the likelihood of private
hydro-development by deferring repayment of $160 million in
reimbursable costs that would otherwise have to be repaid by a
private developer of hydropower on the Diamond Fork System.
Current law requires repayment of this $160 million in costs,
which would incur in development, developing the Diamond Fork
System, and allocated to the power generation purposes of the
project.
Since S. 499 would defer responsibility for these costs, it
would effectively reduce the costs of private power hydro-
development at the site.
The Department understands and appreciates the
legislation's goal of facilitating the development of
hydropower, hydroelectricity power on the Diamond Fork System.
Nonetheless, the administration has serious concerns about
losing the ability to recoup the Federal investment made in
these facilities. The Federal Government may benefit in the
midterm from annual payments for the use of the facilities that
would be paid if a lease entered into, a lease, a lessee
entered into a Lease of Power Privilege arrangement as a result
of this bill.
However, the long-term fiscal implications are unclear as
to how the Federal Government would be made whole for the loss
and repayment of the $161 million in costs.
S. 808, Uintah pre-repayment. Last, S. 808, as introduced
in the Senate on April 13, 2011, allows for a prepayment of the
current and future repayment contract obligations to the Uintah
Water Conservancy District of the costs allocated to their
municipal and industrial water supply on the Jensen Unit of the
CUP and provides that prepayment must result in the United
States recovering the net present value of all repayment
streams payable to the United States.
The Department supports S. 808 as introduced. The District
entered into a repayment contract dated June 3, 1976, in which
they agreed to repay all reimbursable costs associated with the
Jensen Unit of the CUP.
The Jensen Unit's total water supply would was envisioned
at that time to be roughly 18,000 acre-feet because plans
envisioned completion of another pumping plant at a location on
the Green River known as Burns Bench. However, for a variety of
reasons, the Burns Bench feature was never built, and this is
described in my written testimony. Under Reclamation law, water
districts are authorized to prepay--water districts are not
authorized to prepay their M&I repayment obligations based upon
a discounted value of the remaining annual payments. However,
this legislation would authorize early repayment by the
District to the Federal Government. Because there is an
interest component to the repayment streams to be repaid, early
repayment without an adjustment for interest would result in a
lower overall repayment to the United States.
To keep the United States whole, the Bureau of Reclamation
would collect a net present value of the whole amount that
would be due without early repayment. The language in S. 808
has been amended from the language contained in an earlier
version of this legalization. The language introduced April
13th clarifies that this legislation requires that the Federal
Government be paid what it is owed by the Conservancy District.
Because the United States supports the goals of providing for
early repayment under this contract, and S. 808 clearly
establishes that, the Department supports this legalization.
Thank you again for this opportunity to testify, and I
would be happy to answer any questions the subcommittee may
have. Thank you.
Senator Shaheen. Thank you. You came in under 10 minutes,
so----
Mr. Murillo. Thank you.
Senator Shaheen [continuing]. Very good.
Mr. Moe.
STATEMENT OF DARRICK MOE, REGIONAL MANAGER OF THE DESERT
SOUTHWEST REGION, WESTERN AREA POWER ADMINISTRATION, DEPARTMENT
OF ENERGY
Mr. Moe. Chairwoman Shaheen, Senator Lee, I'm pleased to be
here today to speak on S. 519 regarding the allocation of
Hoover Power.
I'm Darrick Moe, the Regional Manager of the Desert
Southwest Region of Western Area Power Administration.
Western's mission is to market and deliver reliable cost-
based power for Federal hydroelectric power facilities such as
Hoover Dam, which is within the geographic area of Western's
Desert Southwest Region.
The Hoover Plant is a significant power resource in the
Desert Southwest. With a rated capacity of 2,074 megawatts,
Hoover supplies clean hydropower to millions of homes in
Arizona, California and Nevada.
Western's post-2017 power allocation effort is composed of
a series of proposals introduced to the public through Federal
Register notices and public forums. Western makes policy
decisions after all interested parties have had an opportunity
for input. Western then considers this input to develop new
Hoover Dam allocations in the public's interest.
Western initiated the process to allocate Hoover Power in
November 2009 by proposing the extension of 95 percent of the
energy and capacity available to market from Hoover to existing
contractors, while making a 5 percent pool available to new
customers. We also proposed 30-year contract terms, and invited
comments on other items. Based on comments from numerous
parties, Western extended the comment period under this notice
through the end of last September.
Western issued its latest Federal Register notice on April
27, 2011. Western therein decided it is appropriate to apply
the Power Marketing Initiative, or PMI, to the Hoover
allocation process. The PMI has been applied to all of
Western's remarketing efforts since it was announced as a final
rule in 1995, following a year public process.
Through the application of PMI, Western balances the public
interest of maintaining resource stability for existing
customers and the regional power grid against the public
interest of providing for widespread use of Federal hydropower
resources by new customers, such as tribal governments and
other eligible customers.
Western also decided on a 30-year to term to achieve a
balance between resource certainty and providing for an
allocation opportunity for future customers at an appropriate
time.
Finally, Western made numerous proposals, including the
amount of energy and capacity to market, the size of the
resource pool for new customers, and provisions for marketing
excess energy.
Since publication of this notice in April, Western has
received comments requesting an extension of the effective date
of these decisions to allow additional time for ongoing
legislative activities. In consideration of these comments,
Western has decided to extend the effective date of those
decisions from May 27 to December 31st of 2011. Additionally,
Western will be extending the comment period for the proposals
to September 1, 2011. The planned public information and
comment forums are also being rescheduled to later dates. A
Federal Register notice announcing these extensions will be
published next week.
There are numerous steps ahead of the administrative
process. We currently project contracts for Hoover Power would
be completed in the spring of 2015. It is important the process
be finalized well ahead of 2017 to provide contractors time to
balance their energy portfolios and make required transmission
arrangements, and to allow related State agencies time to carry
out their allocation process.
Western has reviewed S. 519. We appreciate the work done
over the last year to address concerns Western had with a prior
version of this bill, such as allowing for 36 months for
Western to complete its administrative process under the bill.
Western's written testimony notes areas of departure between
the current administrative process and S. 519, and provides
additional background.
The broad outline of S. 519, however, is similar in many
respects to Western's current proposal. Both would result in a
resource pool for new customers. Western's current proposal
would result in a similar size resource pool being allocated to
existing customers and new customers, as compared to S. 519.
It is Western's mission to market Federal hydropower. We
are using due diligence in moving this process forward to
allocate the vitally important Hoover resource in the public's
interest, and in a timely manner. We also stand ready to
implement S. 519, and will apply ourselves accordingly should
it be enacted by Congress.
I would be pleased to answer questions.
[The prepared statement of Mr. Moe follows:]
Prepared Statement of Darrick Moe, Regional Manager of the Desert
Southwest Region, Western Area Power Administration, Department of
Energy, on S. 519
Madam Chairwoman and members of the Subcommittee, I am Darrick Moe,
Regional Manager of the Desert Southwest Region, speaking on behalf of
Timothy J. Meeks, the Administrator of the Department of Energy's
Western Area Power Administration (Western). I am pleased to be here
today to discuss S. 519, the Hoover Power Allocation Act of 2011. This
legislation seeks to amend the Hoover Power Plant Act of 1984. The
legislation proposes revised allocations of the generation capacity and
energy from the Hoover Dam power plant, a feature of the Boulder Canyon
Project (BCP), after the existing contracts expire on September 30,
2017.
Western's mission is to market and deliver reliable, renewable,
cost-based hydroelectric power from facilities such as Hoover Dam.
Hoover Dam was authorized and constructed in accordance with the
Boulder Canyon Project Act of 1928. Pursuant to this Act, the Secretary
of the Interior was authorized to contract for the sale of generation
based upon general regulations as he may prescribe. Subsequent power
sales contracts were executed that committed Hoover power through May
31, 1987. With the passage of the Hoover Power Plant Act of 1984,
Congress authorized the Secretary of the Interior to implement an
uprating program, which increased the generation capacity of the Hoover
Dam facilities, to make additional facility modifications, and to
resolve issues over the disposition of Hoover power, post-1987. Western
proceeded to market Hoover Dam power and entered into 30-year term
contracts with the current Hoover contractors in accordance with the
Hoover Power Plant Act of 1984, and Western's Conformed General
Consolidated Power Marketing Criteria. This process resulted in the
allocation of 1,951 megawatts of contingent capacity with an associated
4,527,001 megawatt-hours of firm energy. Contingent capacity is
capacity that is available on an as-available basis, while the firm
energy entails Western'sassurance to deliver.
The Hoover power plant is a significant Federal hydroelectric power
resource in the Desert Southwest with a maximum rated capacity of 2,074
megawatts. Under existing Federal law and policy, Western markets
Hoover power at cost. Hoover power is hydropower and is considered
``clean energy'' with a minimal carbon footprint. The Hoover Dam power
plant is able to ramp up and down rapidly and is used by contractors
for various power-related ancillary services. For these reasons, Hoover
power is an extremely valuable resource for power contractors in the
southwestern United States.
The existing power sales contracts between Western and the
contractors will expire on September 30, 2017. As this expiration date
becomes more prominent on the planning horizon, efforts have progressed
among both Federal and non-Federal sectors to determine the allocation
of Hoover Dam power after 2017.
In accordance with policy and existing Federal law, Western's post-
2017 power allocation effort comprises a series of proposals introduced
to the public through public information forums andpublic comment
forums. Western makes policy decisions only after all interested
parties have been provided ample opportunity to be engaged in the
process and public input has been carefully considered to develop new
Hoover Dam allocations that are in the public's best interest and
provide widespread use of this Federal resource.
Western's public process to allocate Hoover Dam electricity was
initiated on November 20, 2009, in a Federal Register notice that
proposed several key aspects of the allocating effort. Among other
things, this Federal Register notice proposed the application of
Western's Power Marketing Initiative (PMI) developed under the Energy
Planning and Management Program (EPAMP), the extension of amajor
percentage of the marketable resource to existing contractors,
reservation of an approximate 5% resource pool to be allocated to
eligible contractors, and provision of 30-year contract terms.Western
conducted three public information forums from December 1-3, 2009.
These public information forums were well attended by current customers
and interested parties, including Native American tribes, and engaged
the attendees through question and answer sessions. Public comment
forums were held from January 19-21, 2010. All interested parties were
provided an opportunity to submit comments related to Western's
proposals contained in the November 20, 2009 Federal Register notice.
After considering comments received, in an April 16, 2010 Federal
Register notice, Western extended the comment period from January 29,
2010, to September 30, 2010. This extension provided interested parties
additional time to submit comments and allowed Western to consult with
tribes to inform them of the remarketing process.
After considering comments received, Western announced in an April
27, 2011 Federal Register notice its decision to apply its EPAMP PMI to
the BCP remarketing effort. The PMI has been applied to all of
Western's remarketing efforts since it was announced as a final rule in
1995 following a four-year public process. Application of the PMI to
the BCP expressly protects and reserves a major portion of the existing
customers' allocations while also providing potential customers, such
as tribal governments and other eligible customers, an opportunity to
acquire an allocation. The PMI has historically provided a balancing of
the needs of the existing customers with those of prospective
customers. Western also decided on a 30-year contract term to achieve a
balance between resource certainty and providing for an allocation
opportunity for future customers at an appropriate time. Finally,
Western also made additional proposals and is seeking further comments
on the amount of marketable contingent capacity and firm energy, the
size of the resource pool to be created for new customers, and excess
energy provisions. As described in the Federal Register notice, a
public information and comment forum was established for all interested
parties to provide written and oral comments on these proposals. The
comment period for these proposals was initially set to close June 16,
2011.
Western is currently in the process of publishing a Federal
Register notice that will extend the close of the comment period
established in the April 27, 2011 notice to September 1, 2011. This
Federal Register notice will also extend the effective date of the
decisions announced in the April 27, 2011 notice to December 31, 2011.
Western is also rescheduling the public information and comment forums
for later this year. This extension provides additional time for on-
going legislative activities, as well as additional opportunity for
interested parties, including Native American Tribes, to consult with
Western and comment on the proposals.
There are numerous steps ahead in the administrative process.
Western currently projects that this process will be completed with
finalized contracts in the spring of 2015. It is important that the
process be finalized well in advance of 2017 to provide customers the
time to balance their energy portfolios and make required transmission
arrangements, and to allow related state agencies time to carry out
their allocations process.
Western has reviewed S. 519. There are several similarities between
the draft legislation and Western's proposals, and there are some
departures. To provide background that may be useful to the
Subcommittee members as this bill is considered, I'll address some of
these differences in mycomments.
All of Western's allocation efforts are open to public
participation and conducted in accordance with the Administrative
Procedure Act. At each stage of the process, Western proposes actions
and/or policy to be considered and is open for public comment and
input. Western believes soliciting and integrating public input into
policy decisions allows Western to develop results that are in the
public's best interest and lead to the most widespread use of this
resource.
Western has 15 current contractors who receive an allocation of
Hoover power. Two of those existing contractors are the Colorado River
Commission (CRC) and the Arizona Power Authority (APA). CRC and APA
sub-allocate their Hoover power to customers under prescribed
guidelines and regulations. Both S. 519 and Western's administrative
effort propose an amount of resource to be allocated to new customers,
including Native American Tribes. S. 519 proposes certain quantities to
be allocated to APA and CRC for their disposition to new customers.
While it is anticipated that new customers to APA and CRC could result
from this effort, Western's process affords the opportunity to fully
seek public input and assures all interested parties are considered in
the power's disposition.
Western has received numerous written comments and statements from
Native American tribes expressing concern that their interests have not
yet been fully vetted and considered. In recent years, tribes have been
active in Western's remarketing efforts, and one goal of Western's
Strategic Plan is to seek partnerships with tribes on numerous
initiatives. I believe that soliciting input from tribes and other
entities that do not already have an allocation of Hoover power is in
the public interest. Western has reached out to tribes specifically in
this remarketing effort through letters, phone calls, meetings, site
visits, and consultations.
S. 519 would direct that Hoover's full maximum rating of 2,074
megawatts of capacity be allocated to Hoover customers in a multi-
faceted approach. As described in Western's April 27, 2011
FederalRegister notice, we propose to market 2,044 megawatts of
contingent capacity; 30 megawatts below the maximum rating. Retention
of project capacity to support the reliability of the Federal electric
system is relatively common among the Power Marketing Administrations.
Western is currently able to utilize Hoover Dam capacity that is
available in excess of 1,951 megawatts. The preservation of 30
megawatts of contingent Hoover Dam capacity for use by Western for
project integration purposes should provide the tools we need to meet
our mission and statutory requirement ofdelivering reliable Federal
hydro-generation. Western manages multiple federally owned generation
and transmission projects in the Desert Southwest on a minute-by-minute
basis 24 hours a day. While these projects are financially segregated,
they are operated as an integrated system. This 30-megawatt capacity to
be held by the Federal Government would provide significant benefit to
theoperation of the integrated projects and the Western Area Lower
Colorado balancing authority that Western operates. Retaining 30
megawatts would also likely allow our Hoover Dam power customers to
experience cost-neutral conditions. Should Western be unable to retain
approximately 30 megawatts, we would expect to procure replacement
power from the market at a higher cost, if itis available. These higher
costs would in turn need to be passed through to Western customers in
the form of higher rates.
S. 519 expressly requires that each contract offered to a new
allottee for Hoover Dam power should require the new allottee to
execute the Boulder Canyon Project Implementation Agreement.
Westernfinds significant value in the provisions and results of the
Implementation Agreement. However, this agreement was jointly
constructed between Western and our customers for unique circumstances
that existed in 1994. Should this requirement be retained, the current
Implementation Agreement wouldneed to be evaluated and potentially
revised to accommodate current conditions. We support the universal
benefits achieved by the Implementation Agreement and will work with
our customers todetermine the appropriate documentation to meet all of
our customers' needs; both current and future.
S. 519 expressly requires that each contract offered to a new
allottee for Hoover Dam power includes a provision requiring the new
allottee to pay a proportional share of its State's funding
contribution for the Lower Colorado River Multi-Species Conservation
Program, known as the LCR MSCP. The LCR MSCP is a 50-year, multi-
stakeholder, Federal and non-Federal partnership, responding to the
need to balance the use of lower Colorado River water resources and the
conservation of native species and their habitats in compliance with
the Endangered Species Act (ESA). The LCR MSCP isa comprehensive
approach to species protection developed after nearly a decade of work.
This program is funded on a cost-share basis comprised of 50-percent
Federal and 50-percent non-Federal. The states of Arizona, California
and Nevada have worked internally with water and power customers to
fund each state's respective share. S. 519 recognizes these funding
requirements and obligates new power customers to contribute to this
funding in a proportional manner. Supporters of S. 519 note that the
50-year obligation of the LCR MSCP is, in part, reason to proceed with
50-year Hoover power supply contracts. Western continues to review the
LCR MSCP requirements in our administrative process. However, Western's
position is that the 50-year LCR MSCP term need not coincide with the
Hoover Dam power sales contracts' term. The adoption of a 50-year
contract term, as opposed to Western's decision to apply 30-year
contract terms, could potentially exclude evolving classes of customers
in decades to come. The modern day electrical industry is dynamic in
its regulations, technologies, operations and participants. Western
notes that we currently provide Federal hydropower allocations to 87
federally recognized Native American tribes. Many of these tribal
customers are new to Western in the last 20 years. The landscape of
potential customers in decades to come has the capability to yield new
Hoover customers, as we strive to meet the needs of all our customers;
existing and future.
As drafted, S. 519 states that Subdivision E of the General
Consolidated Power Marketing Criteria or Regulations for Boulder City
Area Projects published in the Federal Register on December 28, 1984,
(Criteria) shall be deemed to have been modified to conform to this
legislation. Western would like to refine this statement as Western's
December 28, 1984, Federal Register notice is more precisely titled
Conformed General Consolidated Power Marketing Criteria or Regulations
for Boulder City Area Projects (Conformed Criteria). Western published
the Criteria on May 9, 1983, which was in need of conformance per the
Hoover Power Plant Act of 1984. Pursuant to the Hoover Power Plant Act
of 1984, Western conformed the 1983 Criteria in its December 28, 1984,
Federal Register notice. In doing so, the pertinent section is now
Subdivision C of the Conformed Criteria. If S. 519 is to move forward,
edits would be needed to refer to Subdivision C Western's Conformed
Criteriaand not Subdivision E of the Criteria.
Western respectfully recognizes that our administrative process is
not the exclusive means of allocating Hoover power. I would welcome the
opportunity to work with this Subcommittee to address the technical
concerns I have raised and to ensure the widespread use of this
valuable resource as work continues on this legislation. In the absence
of congressional action, Western will uphold our authority and
responsibility to market Hoover power consistent with historical
statutes and in concert with the rules and regulations as the Secretary
of Energy prescribes.
This concludes my prepared remarks and I would be pleased to answer
any questions you or members of the Subcommittee might have.
Senator Shaheen. Thank you very much, both Mr. Murillo and
Mr. Moe.
Mr. Murillo, I will start with you on the C.C. Cragin
project. We appreciate your having someone from the Forest
Service here to help respond.
Your testimony indicates that the Reclamation, that
Reclamation and the Forest Service have previously worked
together on management issues relating to this project, and
that the administration believes that the legislation provides
a good approach for the future management of the project.
To your knowledge, are there any outstanding maintenance
issues within the project corridor that are located on Forest
Service lands that the Salt River Project has not been able to
address?
Mr. Murillo. My understanding is that they had some exposed
pipe they there were trying to, that they addressed last year.
The Salt River Project meet with us yearly, and they also meet
with the Forest Service. So, what I've been told is, most of
the work that they're looking at this year is pretty much
routine work.
Senator Shaheen. I assume the Forest Service agrees with
that--the person who's here. Good.
Are there any plans to develop an interagency agreement to
ensure that the dam and pipelines can be properly maintained,
and if it----
Mr. Murillo. Thank you for the question. Yes, what we're
looking at is, they're, the Salt River Project has, they have a
tri-party agreement that the Bureau of Reclamation, the Forest
Service, and Salt River Project signed, and it is associated
with 6 other projects that they manage. So, we're looking at
developing some type of MOU that basically mirrors that
agreement that we have in place.
Senator Shaheen. Do you expect that MOU to go forward
pretty quickly, or are----
Mr. Murillo. We're hoping we've been working together to
try to come up with some language that's acceptable to
everybody. So, we're hoping that--we've already got an MOU in
place that we can go ahead and draft this memo from, so, we're
hoping it will move forward fairly quickly.
Senator Shaheen. Good. Although S. 201 specifies that
Reclamation and the local water districts should have the
responsibility for compliance with all environmental laws that
are applicable, will Reclamation coordinate with the Forest
Service if necessary during this process?
Mr. Murillo. Absolutely. When we look at environmental
compliance, we're going to coordinate with whatever agency it
applies to.
Senator Shaheen. Great.
I'm then going to move on to S. 419, the Dry-Redwater
Regional Water System. As I understand your testimony, Mr.
Murillo, Reclamation does not question the need for a rural
water system in the area of eastern Montana that's covered
currently under the bill, but part of the reason that you're
unable to support the project is that there's currently a
backlog of funding for the projects that are already
authorized. So, can you address how you might, what kind of
plan you have in place going forward to address the backlog
that currently exists, and how the Redwater project might
ultimately fit in that?
Mr. Murillo. Right now we have a Rural Water Program in
place, and we have criteria that's in place that basically
helps us prioritize the work that's in front of us. When you
look at that O&M--there's existing facilities that have O&M
costs. We allocate money to that initially. Also, we look at
how complete a project is. If they're 80 percent complete, they
get extra points. Then, also, the involvement of tribes. So,
there's 3 major criteria we look at. Then, those that don't fit
that fall into another category. Then we take a look at, see
whatever aspects of the project would basically raise it to the
top.
The Dry Redwater project, once that gets approved, they're
basically going to be falling within the same criteria, and
there's only a limited amount of funding there, so they'll be
competing against the other projects for that funding.
Senator Shaheen. During his recent testimony to the Senate
Energy and Water Appropriations Subcommittee, Commissioner
Connor described a set of funding criteria for the Rural Water
Program that are under development. Is the purpose of the
criteria to help Reclamation prioritize funding needs for the
program?
Mr. Murillo. Yes, it is.
Senator Shaheen. When will the new criteria be available
for review?
Mr. Murillo. We're hoping to have something available mid
this year, mid to the end of this year.
Senator Shaheen. Can you speak at all to how they will be
different from the interim final rule that was put in place in
2009?
Mr. Murillo. My understanding is that we're going to try to
be consistent with that rule.
Senator Shaheen. OK.
Just a final question on this legislation. One of the major
concerns that Reclamation had when the bill came up during the
last Congress was that the former version of the legislation
didn't follow the procedures that had been outlined in the
Rural Water Supply Act. It appears that the version of the bill
that has been introduced in this Congress has attempted to more
closely follow the process required by the existing law.
If the project proponents are able to complete the
feasibility study they're currently working on to your
satisfaction, is Reclamation willing to continue to work with
the sponsors on the next steps for the project?
Mr. Murillo. Yes. If the feasibility study's complete, we
have a Rural Water Program in place, and we'll go ahead and
follow those, execute that program.
Senator Shaheen. Do you have any other recommendations for
the sponsors and the project proponents on how to get safe,
clean drinking waters for their communities? I mean, obviously,
this is an ongoing challenge.
Mr. Murillo. Yes. That's part of why we need the
feasibility study completed, because that will come up with
different options of how to get safe drinking water there.
Senator Shaheen. Thank you very much. My time has expired.
Senator Lee.
Senator Lee. Thank you, Senator Shaheen.
Thank you both for your testimony.
Mr. Murillo, I want to talk to you about S. 499 for a
minute. You indicated in your written testimony that ``because
payment of $161 million of allocated power costs would be
postponed indefinitely under this legislation, it is unclear
what the long-term fiscal implications of enactment of this
legislation would be, and how the United States Treasury would
be made whole.'' This is on the fourth to the last paragraph on
the final page of your written testimony on S. 499.
You then go on to say that ``the legislation would
potentially permanently postpone the anticipated receipts to
the United States Treasury at the expense of the Federal
taxpayer.'' But this presupposes that there is money that would
be paid if in fact you didn't develop this, doesn't it?
Mr. Murillo. Yes. What we would be looking at is, we would
be looking at completing the project itself--the distribution
system. After that was complete, we would be looking at
possibly developing hydropower ourselves. If we did that, we
would be asking the power users to basically help us recoup
that cost. If we didn't go there, then we may have to do
another reallocation and see if we reallocate those costs to
the current beneficiaries.
Senator Lee. Right. But, there's a, the 2004 Definite Plan
Report outlines the potential for construction of hydropower
facilities at this location, and I believe estimates that it
has a generating capacity of about 50 megawatts, is that right?
Mr. Murillo. Yes.
Senator Lee. In your opinion, is it feasible, you know,
would it be feasible under any circumstance for a 50-megawatt
facility to generate support, or, user fees to make it
sufficient, that would be sufficient to support payment of $5.3
million a year for the next 50 years? Is that possible?
Mr. Murillo. I don't have those numbers. But I can get that
information for you and provide it for the record.
Senator Lee. OK. If it's not possible--if generating
capacity of 50 megawatts couldn't support a payment of $5.3
million a year for the next 50 years, and if this is, in fact,
sub-cost that the U.S. Government has incurred, wouldn't it
make more sense to allow this to move forward--to allow this
source of clean, inexpensive, reliable power to be generated,
with the understanding that it would likely generate about
$400,000 a year in payments to the Federal Treasury--which is
more than is being generated right now?
Mr. Murillo. That's true. But, like I indicated, if we
don't develop hydropower, and if we're looking for a revenue
source, we may go back and have to reallocate that money to the
current beneficiaries of the project.
Senator Lee. OK. But, that's a pretty big ``if,'' isn't it?
Mr. Murillo. It's something that we would definitely take a
look at.
Senator Lee. Another ``if'' is identified, I think, in the
same paragraph of the, of your written testimony that I cited a
minute ago. You say at the end of that paragraph, ``While it is
not clear at this time whether a non-Federal developer would
propose a hydroelectric project at Diamond Fork under current
law''--meaning, without the change that would be brought about
by S. 499--if this were to occur, repayment of the allocated
power costs would begin after the hydroelectric project is
completed, and average 5.3 million a year for 50 years.
But again, it seems to me that that is a pretty big ``if.''
If by going in and starting this, someone would have to agree
at the outset to pay $5.3 million a year every year for the
next 50 years, it seems pretty unlikely that that's going to
happen.
Mr. Murillo. That's one of the things that we're going to
have to take a look at if a private investor comes in, or the
Federal Government looks at installing hydropower there.
Senator Lee. OK. But if someone comes along and says, ``I
will do this, and I will pay $400,000 a year throughout the
life of the project,'' then, that would be $400,000 a year more
than the Federal Government's getting right now. With it we've
got 50 megawatts of additional, clean power on the grid.
Mr. Murillo. As I mentioned, it's more than we're getting
now. But in order for us to recoup the costs, like I mentioned
before, if we have to, we may have to take a look at
reallocating those costs.
Senator Lee. OK. Thank you.
Thank you, Chairman.
Senator Shaheen. Thank you.
Just to continue to follow up on S. 499, as I understand
your testimony, it is possible that hydropower may be developed
more quickly within this portion of the Central Utah Project if
the legislation is passed than without the legislation. Is
that, am I understanding that correctly?
Mr. Murillo. If the legislation is passed, it's probably
going to motivate the private investor to develop power at that
facility. If they do that, since there's authorization for
power there, you know, CUP may be looking at using the Lease of
Power Privilege process. That will take them, you know, you've
got to go out with an interest announcement on the Federal
Register, and that may take, you know, 2 or 3, 4 months. Once
they make the selection, the process that you have to go
through to actually sign the agreement, that may take another 2
or 3 years.
Senator Shaheen. So, is there anything that can be done now
to get a head start on this process?
Mr. Murillo. You know, a few things that we can take a look
at. It just depends on the site itself, and what resources we
have. But when we talk to investors about how we can make this
more affordable to the investor, some things we can look at is,
identify any type of cultural resources that might be impacting
the project, any type of land or water restrictions that are in
place, and see if we can recommend any type of mitigation for
them.
Senator Shaheen. How will the environmental impacts of a
future hydroelectric project be addressed?
Mr. Murillo. If they install a hydro facility, and if it
falls within the current footprint of the facility, and if the
impacts have already been addressed, then you might be looking
something like, if it was EA, Environmental Assessment, you
might be looking, something, at a supplemental assessment, or a
categorical exclusion. If it falls outside of the footprint,
then we're just going to have to re-evaluate the need for,
process itself. Sometimes it may fall outside because of the
transmission line you have to install to make the
interconnection.
Senator Shaheen. Are you comfortable that that can be done
in a way that ensures environmental safeguards?
Mr. Murillo. Absolutely. Yes.
Senator Shaheen. OK. Does Reclamation have any recent
examples of offers to lease power within the Central Utah
Project that could provide a roadmap for how hydropower in this
part of the system may be developed?
Mr. Murillo. Actually, we have 4 Lease of Power Privilege
projects that are currently operating, and we can provide that
information as a roadmap.
Senator Shaheen. That would be helpful.
So, are there any amendments that you might suggest that
would make this legislation address your concerns?
Mr. Murillo. There, if there were any amendments that we
would be looking at, because of the budget climate we're in
right now, we'd probably be focusing on how to recoup the
capital investment.
Senator Shaheen. Thank you.
Finally, on S. 808, the Uintah Water District, your
testimony identifies different repayments amount for, amounts
for this project, depending on whether the amounts are
discounted or whether total project costs are included.
If the legislation passes, how will reclamation and the
Water District determine the correct amount to be repaid, in
order to keep the Federal Government whole?
Mr. Murillo. We would have to perform a final cost
allocation. Once that is performed, then we take a look at the
payment stream and then apply the discount rate.
Senator Shaheen. OK. Is that something that you do on a
regular basis with projects?
Mr. Murillo. I wouldn't say we do it on a regular basis.
But I do know that there are other projects where we've
executed early payment.
Senator Shaheen. So, it's not something new?
Mr. Murillo. It's not something brand new for us.
Senator Shaheen. OK. Thank you.
Finally, on S. 519, for Mr. Moe, you've described the
administrative proceedings that Western announced earlier this
year. But you've also indicated that Western published a notice
that will delay the effective date of those decisions until
December. So, is Western willing to withdraw the decisions
themselves until a later date, in addition to extending the
date on which Western intends to make them become effective?
Mr. Moe. The Federal Register notice that we have
discussed, based on comments that we've received recently, is
to extend the effective date of those decisions. We have not
had internal discussions about undoing the decisions
themselves.
Senator Shaheen. Why does Western feel like it's necessary
to pursue an administrative allocation now, when the allocation
has traditionally been done by Congress?
Mr. Moe. We believe that it's appropriate to continue to
keep the process moving. We think, based on the current
roadmap, that it would take until about the spring of 2015 to
complete our process, because there's an awful lot of steps
ahead of us in the process. Of course, that needs to be
finished well ahead of 2017, because you need time for the
people to get the contracts, and those that don't get the
contracts, to make other energy allocation decisions, to make
transmission arrangements.
So, well, we've been trying, well, we've certainly been
using due diligence in moving the process along and taking
plenty of time to consider comments and so on--we extended the
last comment period for almost a year--we do feel it's
important to continue to move the process along, in the event
that Congress should decide not to act on S. 519.
Senator Shaheen. Thank you.
Senator Lee.
Senator Lee. Mr. Murillo, I just wanted to follow up with
you little bit on some of the comments on S. 499. We talked
about the possibility of costs reallocation. I mentioned that
that might be a big ``if.'' But, as I think about it, it may be
an even bigger ``if'' than I was acknowledging previously.
Doesn't Section 211 of the Central Utah Project
Compensation Act--Completion Act, prohibit that kind of cost
reallocation?
Mr. Murillo. I'm not sure of that. I don't know if that----
Senator Lee. OK.
Mr. Murillo [continuing]. Does or not.
Senator Lee. I believe that it does. If that's the case,
let's assume for moment, let's assume for purposes of our
discussion today and this hearing, that that is the case, as
I'm pretty confident that it is. If I'm right, then wouldn't it
make perfect sense to move forward with this legislation? In
other words, if what we are faced with is a binary choice--we
either proceed with S. 499 or we don't--if we proceed with it,
the Federal Government, the U.S. Treasury gets $400,000 a year;
we get 50 megawatts of clean energy on the grid that is not
there now. If we don't, we get nothing. We get neither the
power, nor the money. So, assuming I'm correct about Section
211 of CUPCA, wouldn't it make the most sense for us to proceed
with this?
Mr. Murillo. You know, if we're looking at a proposal that
makes fiscal sense, you know, that's something that we're
definitely going to entertain.
Senator Lee. OK. That would make fiscal sense, with that
understanding, wouldn't it?
Mr. Murillo. We'd have to do the analysis.
Senator Lee. OK. Thank you very much.
Mr. Murillo. Thank you.
Senator Shaheen. I would like to go back, Mr. Moe, to S.
519, because there have been some assertions from parties
interested in this issue that Western doesn't have the
authority to administratively allocate power from the Hoover
Dam. How do you respond to those concerns?
Mr. Moe. Thank you. I appreciate that. I, we published our
first Federal Register notice in November 2009, and proposed
the application of allocating power through the Power Marketing
Initiative at that time; extended comments for that process all
the way until September of last year. The Power Market--and
have considered those comments since.
The Power Marketing Initiative is a regulation that Western
promulgated in 1995 after 4 years of public comment, under
which, under that regulation, existing contractors would
receive the majority of the pool, but new customers would be
allowed to apply for a small percentage of the pool in order to
allow for widespread use of the Federal asset. We've applied
that process to every remarketing effort since it was issued as
a final rule in 1995. Again, in the case of the Hoover
allocations, we've asked for comment, and considered those
comments in terms of Hoover specifically.
We believe that the 1928 Boulder Canyon Act explicitly
authorizes the allocation of a new pool by saying that the
process should be in compliance with existing regulations,
which our Power Marketing Initiative is an example of. So,
that's a summary of why we believe it's appropriate.
Senator Shaheen. So, if this legislation passes, will
Western stop its current efforts to administratively allocate
power from----
Mr. Moe. Right. The legislation calls for Western to take
action, but in, but under the legislation--the broad outlines
of what the legislation would do are actually pretty similar to
what our current proposals are. But, yes, we would, to the
degree that our differences--clearly, we would move to adopting
S. 519, or whatever the final legislation is, if Congress
should enact it. Again, we believe--and we appreciate the
efforts to work with us, and believe that it's something that,
you know, could be done also.
Senator Shaheen. So, would you elaborate a little bit more
on how the Power Marketing Initiative criteria that Western
proposes would be different than the criteria that are
applicable to the existing contracts?
Mr. Moe. The Power Marketing Initiative essentially is a
regulation where you extend for the existing contractors a
major percentage of the pool, but then you open a new pool for
new customers to allow for widespread use. So, for example, 30
years ago, when the Hoover bill in 1984 was passed, Western did
not have regulations in place that accommodated tribal
customers very well. The Power Marketing Initiative, when it
was announced in 1995, also changed our regulations to allow
for those customers to be able to be customers without having
utility status, was kind of the major change we made in the
regulations there. So, the Power Marketing Initiative is the
regulation by which we allow for new customers.
Now, the current--in terms of comparing it to S. 519--S.
519, you know, also allows for a 5 percent pool for new
customers. So, in terms of the eventual impact, you know, I
think there'd be, they'd fairly similar. But I'm not sure--am I
missing the----
Senator Shaheen. No. No, that's----
Mr. Moe. Is that your question? OK.
Senator Shaheen [continuing]. That's why I'm asking.
So, I don't have any further questions.
Senator Lee, do you have anything else that you would like
to ask?
Senator Lee. Nothing further. Thank you.
Senator Shaheen. OK.
Thank you both very much for appearing here.
At this time I will close the hearing.
[Whereupon, at 3:22 p.m., the hearing was adjourned.]
APPENDIXES
----------
Appendix I
Responses to Additional Questions
----------
Responses of Darrick Moe to Questions From Senator Shaheen
Question 1. Which provisions of federal law support Western's
position that it has authority to allocate power from Hoover Dam after
the existing controls expire in 2017?
Answer. Section 5 of the Boulder Canyon Project Act (Project Act)
(43 U.S.C. Sec. 617d) authorized the Secretary of the Interior to
contract for the generation and delivery of electrical energy to
States, municipal corporations, political subdivisions, and private
corporations under such regulations as he may prescribe. Exercising
this authority, the Secretary made initial allocations of Hoover Dam
power under regulations promulgated in 1930 and amended in 1931. The
1931 regulations allocated all of the Hoover firm energy to California,
Arizona, and Nevada entities, although initially all of the power was
placed under contracts with California entities because Arizona and
Nevada did not take their allocations until 1940 and 1945 respectively.
Contracts under the 1931 regulations ran for 50 years (the maximum
length permitted under the Project Act), from June 1, 1937, when Hoover
power generation began, until May 31, 1987.
On July 19, 1940, the Boulder Canyon Project Adjustment Act
(Adjustment Act) was enacted for the purpose, among other things, of
modifying the method of amortizing the Government's investment in the
project. Pursuant to the Adjustment Act, the Secretary of the Interior
issued regulations setting forth the basic principles the Bureau of
Reclamation would follow in establishing electricity rates for the
project.
The Department of Energy Organization Act of 1977 (DOE Act),
transferred the power marketing functions previously held by the
Secretary of the Interior to the Secretary of Energy. Pursuant to
section 302 of the DOE Act (42 U.S.C. Sec. 7152), authority to perform
these functions for the Boulder Canyon Project (BCP), was vested in the
Administrator of the Western Area Power Administration.
The Hoover Power Plant Act of 1984 provided for the allocation of
Hoover Dam power for the period from June 1, 1987, to September 30,
2017, however it did not alter Western's underlying authority to market
power from Hoover Dam under the Project Act. If new allocation
legislation is not enacted, Western still retains the statutory
authority to market Hoover Dam power pursuant to section 5 of the
Project Act.
Question 2. What differences exist between Western's Power
Marketing Initiative criteria, and the marketing criteria that
currently apply?
Answer. As proposed, Western's Power Marketing Initiative (PMI)
would extend 95% of the BCP resources to existing customers, resulting
in a 5% resource pool to be allocated to eligible customers. It also
would increase the marketed capacity from 1,951 megawatts (MW) to 2,044
MW. Otherwise, the application of the PMI would retain the existing
criteria for the BCP marketing area.
Question 3. What public process will Western follow for allocations
of power from Hoover Dam, if S. 519 is enacted?
Answer. If S. 519 is enacted by Congress, Western will implement
the provisions of the legislation, including the allocation of certain
``Schedule D'' power. To accomplish this allocation, Western would
follow a process consistent with the Administrative Procedure Act, that
entails publically announced proposals, public information forums,
public comment forums, and decisions made in consideration of comments
received.
Question 4. What would cause Western to procure power at a higher
cost if it was unable to retain an allocation of the power generated at
Hoover Dam?
Answer. In order to reliably operate and maintain its extensive
transmission systems and balancing authorities, Western is obligated to
carry operating reserves to maintain generation capacity set aside to
be used in the event of a system contingency. Due to persistent drought
conditions and the operation of the Colorado River over the last 20
years, Western has very rarely had the opportunity to utilize the 123
MWs of capacity potentially available under the current BCP contracts
for this purpose. Therefore, Western has, and will continue to be
required to procure market-based capacity or supporting energy
products, and pass the costs to its customers through higher rates.
Western has proposed to retain 30 MWs of BCP capacity as an operating
reserve that would greatly diminish the need for these purchases and
provide additional stability to the operation of the Federal electrical
infrastructure. Western's proposal would result in all Hoover-generated
energy (as opposed to capacity) being delivered to the customers of the
project and keep the customers financially neutral.
Question 5. What elements of the current Implementation Agreement
does Western believe should be re-evaluated?
Answer. The current Implementation Agreement (IA) was entered into
between Western and BCP customers to resolve issues present in 1994
relative to the following eleven topics:
1) Replacements
2) Visitor Facilities
3) Amending CFR 904
4) Multi-Project Benefits and Costs
5) Engineering & Operating Committee and Coordinating
Committee
6) Billing and Payment
7) Working Capital
8) Audits
9) Principal Payments
10) Annual Rate Adjustments
11) Uprating Credits
To bring the agreement up to current conditions, there would be
innumerable updates or modifications needed. As an example, the IA
contains references in the Billing and Payment sections to the existing
marketed 1,951 MW of contingent capacity and 4,501,001 of annual firm
energy in its methodologies. S. 519 would modify the marketed capacity
to 2,074 MW. Updates of this nature do not appear to be a major
departure from the intent of the agreement. However, Western believes
it would be in all parties' best interests to re-evaluate the language
in the IA and not unreasonably reinstate existing language which would
be confusing to new Contractors or be inappropriate given the
circumstances.
Question 6. If Western goes forward with its administrative
process, how many tribes would be eligible to receive contracts for
power beyond the 87 tribes that currently receive Federal hydropower
allocations?
Answer. Western has identified 59 Federally recognized Native
American tribes in the BCP marketing area. All 59 of these tribes would
be eligible customers and be able to apply for an allocation under
Western's PMI. Approximately 24 of those 59 tribes currently receive
Federal hydropower allocations from other projects administered by
Western.
Question 7. Does Western have any technical concerns regarding S.
519 beyond the issue raised for Subdivision C of the Conformed
Criteria?
Answer. No, Western has no other technical concerns beyond the
issue raised for Subdivision C.
Responses of Darrick Moe to Questions From Senator Lee
Question 1. Proponents of the legislation argue that Congress, and
not the Administration, should allocate Hoover's future capacity. Why
then, did WAPA decide to proceed with a Federal Register notice action?
Is there a benefit to proceeding administratively? Do you believe the
Administrative process is preferable to Congressional action?
Answer. Western believes there is a public benefit in the
continuance of the current administrative process in parallel to these
legislative efforts because no matter how BCP power is allocated,
structuring agreements between Western and its Contractors will require
time. Western must be prepared to offer and execute BCP contracts
regardless of whether S. 519 is enacted. Interested parties need ample
time to adjust their power resource portfolios after allocations have
been determined. State agencies also need sufficient time in order to
conduct their own allocation processes. Western has no preference for
either the administrative process or Congressional action, however,
under the administrative process, it is possible that a wider customer
distribution of Hoover allocations could occur.
Question 2. The legislation before us would, upon the 2017
expiration of the existing Hoover contracts, allocate the project's
power for the next 50 years. The last time Congress reauthorized the
Hoover project, we approved 30 year contracts--the same time period
envisioned by Western in their Administrative proceeding.
While supporters of the legislation argue that 50 years is needed
in order to coincide with the 50 year Lower Colorado River Multi-
Species Conservation Program (LCR MSCP), Western notes that the
contracts terms do not coincide with the LCR MSCP terms. Will you both
please comment on the issue of a 50 year versus 30 year contract term?
Do you believe the adoption of a 50 year term potentially excludes
evolving classes of customers in decades to come?
Answer. Western does not find a need for Hoover Dam power sales
contract terms to coincide with the LCR MSCP. The initial 50-year term
authorized in the Boulder Canyon Project Act was a means of providing
potential customers flexibility to finance capital investments over a
long period of time. Considering that the initial project investments
have been paid in full, the original logic behind the 50-year term no
longer exists. The adoption of a 50-year contract term would likely
exclude new and evolving classes of customers and perhaps stifle
economic growth and flexibility. The electrical industry is dynamic in
its regulations, technologies, operations and participants. With the
North American Electric Reliability Corporation and Western Electric
Coordinating Council continually changing requirements, growth in
renewable programs, increased tribal interest, and heightened climate
and environmental issues to consider, the hydro-electric industry has
the capability, and strong potential to yield new prospective customers
as well as result in a dramatic evolution of existing customers. The
development of Native American tribes in the electric utility market in
the last 10 to 15 years is an example of how new customers can emerge
in a relatively short period of time. Western's preference to apply a
30-year term is intended to balance the existing
Contractors' needs for sufficient resource planning horizons and
stability and to provide for increased present and future widespread
use of the Federal hydropower resource.
Question 3. In its Administrative proceeding to allocate future
Hoover capacity, WAPA has proposed to retain 30 megawatts of contingent
Hoover Dam capacity for project integration purposes. I'd like Mr. Moe
to explain to the Committee why the 30 mw retention is important to the
Administration. Mr. Murillo, does the Bureau agree that such retention
is necessary?
Answer. In order to reliably operate and maintain its extensive
transmission systems and balancing authorities, Western is obligated to
carry operating reserves to maintain generation capacity set aside to
be used in the event of a system contingency. This operating reserve
requirement varies per hour in the 90-130 MW range. Due to persistent
drought conditions and the operation of the Colorado River over the
last 20 years, Western has very rarely had the opportunity to utilize
the 123 MWs of capacity potentially available under the current BCP
contracts for this purpose. Therefore, Western has, and will continue
to be required to procure market-based capacity or supporting energy
products and pass the costs to its customers through higher rates.
Western studied its anticipated long term operating reserve
requirements and identified the retention of 30 MWs to be an optimal
balance of meeting operating reserve requirements and potential impacts
to Western's customers. Western has proposed to retain 30 MWs of BCP
capacity that would greatly diminish the need for these purchases and
provide additional stability to the operation of the Federal electrical
infrastructure. Western's proposal would result in all Hoover-generated
energy (as opposed to capacity) being delivered to the customers of the
project, and keep the customers financially neutral.
Appendix II
Additional Material Submitted for the Record
----------
Statement of Phyllis Currie, General Manager, Pasadena Water and Power,
on S. 519
Chairman Shaheen and Ranking Member Lee, thank you for holding
today's hearing and for allowing me to submit testimony on S. 519, the
Hoover Power Allocation Act of 2011.
I am Phyllis Currie, the General Manager of the Pasadena Water and
Power. I am submitting testimony on behalf of the city of Pasadena and
the other nine Hoover contractors who are members of SCPPA, the
Southern California Public Power Authority.
The SCPPA is a joint powers authority consisting of 11 municipal
utilities and one irrigation district. Our members deliver electricity
to approximately 2 million customers over an area of 7,000 square
miles, with a total population of 4.8 million consumers. SCPPA members
that are Hoover participants include the municipal utilities of the
cities of Anaheim, Azusa, Banning, Burbank, Colton, Glendale, Los
Angeles, Pasadena, Riverside and Vernon.
Pasadena was one of the original contractors for power from Hoover
Dam. In 1931, Pasadena, along with Glendale, Burbank, Los Angeles,
Metropolitan Water District of Southern California, Southern California
Edison and the States of Arizona and Nevada agreed to pay rates
sufficient to guarantee the federal government that construction costs
of the multi-purpose, almost 1,500 megawatt dam would be repaid in 50
years.
Hoover Dam and power plant were entirely paid for by the original
power users-not by the federal taxpayers. All the benefits of this
multi-purpose dam, including flood control, municipal and industrial
water supply, irrigation and recreation were made possible by the
commitment of these original power users to pay for the dam. Since its
inception, Hoover Dam has provided these multiple benefits to millions
of citizens in Arizona, California and Nevada.
Pasadena was also one of the parties that agreed, in 1984, to
advance fund the costs of uprating the turbines at Hoover, which
resulted in another 500 MW of generation from the dam. Pasadena joined
SCPPA cities Glendale, Anaheim, Riverside, Azusa, Banning, Colton,
Vernon and the States of Arizona and Nevada in that uprating effort
which, again, used no taxpayer money.
The Boulder Canyon Project Act of 1928 authorized construction of
the dam and related facilities, and authorized the Department of the
Interior to allocate the power to the original contractors, including
Pasadena. The Hoover Power Plant Act of 1984 authorized the Hoover
uprating project, re-allocated power to the original contractors and
allocated the new capacity and energy to the uprating participants.
In anticipation of the expiration of current contracts for Hoover
in 2017, power users in Arizona, California and Nevada got together
more than three years ago to begin negotiations that led to S. 519.
The key features of this legislation are as follows:
Authorizes the Secretary of Energy to enter into 50-year
contracts with existing contractors for 95% of the capacity and
energy they now receive;
Gives power users a contract term that matches the financial
commitment made by water and power contractors in the Lower
Colorado River Multi-Species Conservation Plan (MSCP)
legislation signed into law in 2009. The MSCP funds will be
used for 50 years of environmental mitigation on the Lower
Colorado River; and
Creates a 5% ``set aside'' of capacity and energy for new
entrants, including Indian tribes, municipalities, rural
electric cooperatives and irrigation districts that do not now
receive Hoover power.
From Pasadena's point of view, passage of this legislation will
enable us to plan effectively for long-term power supplies to meet
customer demand. It will also offset the higher cost of renewable
resources we will acquire to meet the 40 percent by 2020 target
Pasadena has adopted. All of the other SCPPA Hoover contractors have
adopted similar renewable energy targets. Additionally, California has
enacted state legislation that would require all utilities, including
SCPPA members, to meet a 33% renewable energy standard and 30%
reduction in greenhouse gas reduction by 2020.
And, passage of this bill will match the commitment water and power
users made to fund the MSCP with contracts that ensure the benefits of
the power generated at Hoover.
Pasadena is proud that it was one of the original Hoover
participants and that we were participants in the uprating authorized
in 1984. This unique facility, paid for by power users, not by the
federal government, provides immeasurable benefits to citizens Southern
California, Arizona and Nevada.
We are also proud that the legislation we are discussing today was
agreed-to unanimously by Hoover contractors in the three states. And,
we are gratified to have strong bipartisan support for the bill from
Members of Congress from Arizona, California and Nevada, including
Senators. Dianne Feinstein and Barbara Boxer.
Thank you for the opportunity to submit this statement for the
record. I would be happy to provide the Subcommittee answers to any
questions that you may have.
______
Statement of Donald A. Christiansen, General Manager of the Central
Utah Water Conservancy District, on S. 499
Introduction
Thank you for the opportunity to submit a written statement for
this hearing. I am General Manager of the Central Utah Water
Conservancy District (District), the State sponsor of the Central Utah
Project. I appreciate Senator Orrin Hatch and Senator Mike Lee's
leadership on this bill. The Bonneville Unit of the Central Utah
Project develops water for communities in 10 counties covering three
Congressional Districts. S. 499 will clear away sunk system-wide costs
which constitute an economic roadblock to the development of clean
hydropower in the Diamond Fork feature of the Bonneville Unit. Adding
hydropower capability at existing facilities is a cost-effective and
environmentally sustainable way to build our clean-energy portfolio,
create local jobs and stimulate the economy.
Potential for Diamond Fork Hydroelectric Power Plants
The Supplement to the 1988 Definite Plan Report for the Bonneville
Unit (2004) and the Utah Lake Drainage Basin Water Delivery System
Final Environmental Impact Statement (September 2004) detail the
proposed power facilities that could be built at Diamond Fork. In
general, two hydroelectric power plants would be located in Diamond
Fork Canyon. They are at:
1. The Sixth Water Flow Control Structure with a capacity of
45 MW and,
2. The Upper Diamond Fork Flow Control Structure with a
capacity of 5 MW
The potential Diamond Fork power plants have some similarities and
yet some distinct differences from the Jordanelle power plant. Of
particular importance is the manner in which power costs have been
assigned by the Department of the Interior. $161 million in Strawberry
Collection System sunk costs have been assigned to be recovered from a
future Diamond Fork power plant. This significantly complicates
hydropower development at Diamond Fork. In essence, any developer of
power at Diamond Fork starts in an economic ``hole'' of $161 million
before installing any power turbines or constructing any transmission
lines.
Moreover, power generation at Diamond Fork is based on the ``run of
the river'' (generation which is incidental to water releases), and
therefore Diamond Fork hydropower has less value in energy markets
because it cannot be scheduled to meet peak demands. In fact, Section
208 of PL 102-575 places limitations on the operation of the power
plants at Diamond Fork. The Central Utah Project Completion Act or
``CUPCA'' says; ``Use of Central Utah Project water diverted out of the
Colorado River Basin for power purposes shall only be incidental to the
delivery of water for other authorized project purposes. Diversion of
such waters out of the Colorado River Basin exclusively for power
purposes is prohibited.'' Hence, flow releases through the Diamond Fork
System of aqueducts and pipelines would be dictated by Central Utah
Project (CUP) and Strawberry Valley Project (SVP) water needs and would
be used for electric energy generation at the hydroelectric power
plants as a secondary purpose.
Legislation is needed to defer sunk system costs allocated to Diamond
Fork Power
Because the power costs allocated to Diamond Fork make the project
uneconomic, we approached the Utah delegation with a remedy to defer
these costs similar to other costs that have already been deferred. The
cost allocation was initially done using the Use of Facilities (UOF)
method as directed by the Comptroller General in a letter of January
26, 1994. Application of a strict UOF allocation of costs to power
resulted in an allocation of $540.3 million to power. This amount would
result in a power rate significantly higher than its market value.
Consequently, a modified use of facilities approach was used to
calculate the power allocation. Under this approach, the cost allocated
to power is $161.0 million.
Even with the modified use of facilities approach this amount
allocated to power makes power development very expensive and
infeasible. At a time when the demand for energy is skyrocketing and
the need for renewable energy is paramount, the sensible approach of S.
499 is to defer the costs assigned to power and allow development of
this valuable resource. As was done with Jordanelle dam, the fee paid
to the Federal government for the investment in facilities which make
power development feasible could be negotiated through a competitive
Lease of Power Privilege process. Current market conditions and
construction costs would be known and a reasonable fee could be
established.
The District is an experienced developer of hydropower
The District has a proven track record of developing non federal
hydropower on federal facilities of the Bonneville Unit. In Summit and
Wasatch counties, we worked from the initial design of the Jordanelle
Dam to facilitate outlet plumbing for the eventual installation of the
recently constructed Jordanelle hydropower plant. The District has been
involved in each step of this very successful project, which has a
maximum capacity to generate 12 megawatts of hydropower at Jordanelle
dam. The project has been certified by the Low Impact Hydropower
Institute as ``Green Power''.
The plant began commercial operation on July 1, 2008. The District
developed the Jordanelle power plant in partnership with Heber Light &
Power (a local public power entity) who purchases and markets the
energy. Since it was originally anticipated that federal power would
not be developed at Jordanelle dam, none of the costs of the dam or
system-wide project costs were allocated to power. Therefore, during
the negotiation of the Lease of Power Privilege one of the negotiation
points was to determine a reasonable fee to be paid to the federal
government that would not push the cost of the power beyond market
conditions. The negotiated fee is 3 mills per kilowatt hour escalating
at 3% per annum.
Conclusion
The District stands ready to initiate a process to apply for the
right to develop clean hydropower at Diamond Fork if the economic hole
created by the allocation of sunk system-wide costs is deferred. We
strongly urge your approval of this important legislation as soon as
possible.
______
Statement of Calvin Crandall, Chairman of the Board, Strawberry Water
Users Association, on S. 499
Madam Chairwoman, our own Senator Lee and Members of the Committee,
on behalf of the Strawberry Water Users Association (SWUA) we want to
thank you for allowing us to provide written testimony in support of S.
499, the Bonneville Unit Clean Hydropower Facilitation Act.
S. 499 opens the door to hydropower development in the Diamond Fork
System of the Central Utah Project (CUP), a portion of the CUP shared
with the Strawberry Valley Project (SVP). Diamond Fork power would not
be practicable without passage of S. 499.
Diamond Fork power will produce clean energy by harnessing the
power of SVP and CUP water which is already carried in the Diamond Fork
System. The reason SVP and CUP water is carried in the pipe that makes-
up the Diamond Fork System is to protect natural streams from erosion.
Today the tremendous energy of falling project water is being
wasted, in part as the result of federal red tape that produces
illogical results. S. 499 will remove the barriers, allowing this clean
renewable Diamond Fork energy to be used. Additionally, where no
revenue is currently being produced, a portion of the produced power
revenues will be used for the two Reclamation projects involved. This
is vital as both the SVP and CUP are critical to the future of Utah.
With passage of S. 499, a portion of the power revenue will flow to
the federal government. No federal dollars, and no tax-exempt bonding,
will be used in the construction of Diamond Fork power facilities. This
truly is a win win for everyone involved. We appreciate very much your
leadership in this endeavor.
We would also like to express public appreciation to Central Utah
Water Conservancy District and Don Christiansen for their
thoughtfulness and leadership on this issue. SVP and CUP have much to
gain from the completion of this important project.
When the two projects and the federal government sat down to
negotiate the sharing of project facilities, both parties were clear
that opportunities for the SVP's development of power, using SVP water,
would not be impaired by reason of SVP water being carried in the
Diamond Fork System for the benefit of the environment. We are
appreciative of the ongoing commitment that will assure SWUA that we
will be rightfully compensated for our property right.
That strong commitment is reflected in paragraph 19 of the 1991
Contract that governs the sharing of CUP facilities by both SVP and
CUP. That commitment is also reflected in the Opinion of the Regional
Solicitor dated July 30, 1986. We are also very grateful for Don
Christiansen's personal public reiteration of that commitment during
discussions that lead to SWUA's full support for S. 499.
We very much appreciate your leadership in holding this hearing and
that of Senator Lee and Senator Hatch on this important issue and look
forward to working with you all as this bill moves forward in the
legislative process.
______
Statement of Tod Kasten, Dry Redwater Regional Water Authority (Dry-
Redwater), McCone, Garfield, Richland, Dawson, Prairie County, Montana
and a Portion of McKenzie County, North Dakota, on S. 419
Madam Chair and members of the subcommittee, my name is Tod Kasten.
I am Treasurer of the Dry-Redwater Regional Water Authority. Thank you
for the opportunity to provide testimony the subcommittee in support of
authorizing the Dry-Redwater Regional Water System. I would also like
to thank Senator Max Baucus and Senator Jon Tester for their strong and
continuing support for this project.
The Dry-Redwater will provide a safe and dependable municipal and
rural water supply for the public water supply systems and rural users
that comprise the Dry-Redwater Regional Water Authority. Speaking on
behalf of the Dry-Redwater, I can assure you that our primarily
agricultural based frontier communities in eastern Montana strongly
support all components of the project as a good, clean, reliable source
of water is vital to our existence.
This great local support is evidenced by nearly 3,500 good
intention fees collected. These pre-paid fees show the financial
commitment of the area users for this project. This financial support
represents an equivalent population of nearly 15,000 users which is
nearly 70% of the potential users already financially committed to this
project.
Need for the Project
The Dry-Redwater service area is plagued by problems with water
quality and adequate supply. The public water supply systems within our
boundaries are unable to meet the requirements of the Safe Drinking
Water Act without expensive energy intensive treatment options.
According to the Montana Department of Environmental Quality (DEQ), one
of the public water supply systems who would be served by the proposed
regional system is out of compliance with the Federal Clean Water Act
due to levels of secondary contaminants - sodium and total dissolved
solids.
Many of the existing systems treat their water with chlorine which
in turn has caused problems with elevated levels of disinfection by-
products. Other systems have problems with bacterial contamination and
elevated levels of total dissolved solids, iron, manganese, lead,
copper, sulfate and sodium that render the water nearly undrinkable.
The rural residents in the proposed project area currently obtain
their water, in the majority of instances, from private wells drilled
into shallow aquifers, gravel pockets or deep confined aquifers. Some
rural residents are hauling all of their drinking and cooking water
used either because their well water is undrinkable or there is not a
sufficient quantity to be usable. Many rural residents do report water
quality and/or quantity problems, which is evidenced by the chart of
private well water quality attached at the end of our testimony at the
first hearing of this project under old Senate Bill 637 in July of
2009. There is a Montana Department of Transportation rest stop at
Flowing Wells that is categorized as a public water supply system. This
rest area is located at the junction of MT Highways 200 and 24; which
is a main route to Fort Peck Lake. This rest area is heavily used by
tourists and recreationist visiting Fort Peck Lake. The water source
for this public area has signed for non-use as a potable system-do not
drink the water due to high levels of nitrates and high levels of
coliforms. This system has had to be renovated several times to correct
those deficiencies, but due to the depth of the well and proximity to
on-site sewage disposal facilities this will be a chronic problem.
The majority of the proposed communities to be served are currently
operating their own municipal water systems; all of the communities are
using wells as a source of water. Three communities must treat their
water because of high levels of fluoride which is a health hazard and a
regulated contaminant. A fourth community-Jordan-does not treat its
water but it is high in sodium and total dissolved solids which are not
currently regulated, but has detrimental effects on those drinking it.
A fifth system-Fairview- has high organic levels in its water that has
lead to a disinfection by product violation. The Town operates an iron
and manganese removal water treatment facility that uses chlorine as
the oxidizer; which while effective at removing the iron and manganese,
does have the problem of forming disinfection byproducts.
Based upon preliminary review of the water quality in the wells of
rural users in the proposed service area it indicated that the majority
of them do not have access to the quality of water needed for a healthy
existence. One of the wells, in the project area, serves Garfield
County School District No. 15 and it shows that the sodium level is 447
parts per million (ppm) which exceeds the recommended level of 250 ppm,
the fluoride is 3.35 ppm which exceeds the recommended level of 2 ppm
and it has 1049 ppm of total dissolved solids which is over twice the
recommended level of 500 ppm. This well and the other private wells are
not regulated by National Drinking Water Standards but the detrimental
effects of the water on their users are not any less because they are
not regulated. The treatment of water in a private well is costly and
sometimes complicated depending on what is in the water. A regional
rural water system will allow the rural user to have access to a
reliable, safe, high quality water supply. The public water systems in
the service area are regulated by Drinking Water Standards and must
treat the water they provide to their user to these standards. The use
of a membrane type water treatment facility (reverse osmosis or nano-
filtration) are not typical systems found in smaller towns, but due to
the limited alternatives to remove the regulated contaminates
(fluoride) Circle, Richey and Lambert were forced to use this energy
intensive system that requires a high pressure pump to force the water
through a membrane in order to remove the contaminates. This method of
treatment does not conserve water as much of the water treated is
wasted in back flushing and the process is a large consumer of
electrical power. The requirements for safe drinking water are getting
more stringent every year and these increased regulations equal
increased costs to all public water systems. A small system that
currently treats their water such as Circle, Richey, Fairview and
Lambert will be greatly impacted financially for even minor
modifications needed to meet new drinking water treatment standards.
These costs will be in treatment, distribution and operator
certification costs. The Town of Jordan currently does not treat its
ground water source but does provide disinfection by means of
chlorination. The Town of Jordan, like other public drinking water
systems, must publish an annual drinking water report and following is
an excerpt from the latest report: ``We're pleased to report that our
drinking water is safe and meets federal and state requirements.
However, as many of you know, although our water is labeled as safe to
drink under the Safe Drinking Water Act, some of the unregulated
parameters affect the taste and may affect the health of a limited
population. The concerns are sodium and the total dissolved solids in
the water. The sodium level is high enough that people with high blood
pressure may want to consider a separate source of drinking water. The
total dissolved solids are high enough to have a laxative effect on
people that have not become conditioned to the water. We are aware of
these problems with our source of drinking water, but have been unable
to find a solution that is financially feasible.'' The drinking water
standards for sodium and total dissolved solids will be addressed in
future regulations and the Town of Jordan will need to address these
regulation changes and the costs that will be associated with meeting
those new regulations. By belonging to a regional water system these
small systems will be part of a larger user base, so future
improvements will not have as great of financial impact to the
individual user. In the proposed regional water system there is one
source of water treatment which will replace 5 existing central water
treatment systems. This will greatly reduce the costs, improve
efficiency and effectiveness in the delivery of safe water to all area
users. The installation of a single conventional water treatment plant
will greatly reduce the energy consumption utilized in the treatment
process since the 3 energy intensive reverse osmosis system will be
retired. Another benefit of the regional water treatment facility is
the reduced volume of wastewater generated during the treatment
process. A reverse osmosis facility must reject 35% to 50% of the water
that comes into it to remove the fluoride and sodium down to acceptable
levels. This reject water must be stored and treated in the Town's
wastewater system which in Richey, Circle and Lambert causes storage
problems. A conventional water treatment plant will waste 5% to 10% of
the incoming water to clean the filters of the contaminants removed
during the treatment process. Unlike the waste stream from a reverse
osmosis treatment facility that has high concentrations of sodium,
fluoride and other deleterious chemicals the waste stream from the
surface water plant can be placed in a settling pond and after a period
of 2 to 3 weeks over 80% of the waste water could be reused for
irrigation or stock watering. The landowner that is selling the land
for the proposed water treatment facility has expressed a great
interest in being able to utilize this water. A regional water system
also mitigates the potential negative impacts of migration from one
small community. For example, if 15 users leave Richey that is 10% of
their user base, but if Richey joins the Dry-Redwater project and
Richey loses 15 users; it is less than 1% of the total user base.
Town of Circle
1.The Town of Circle has a municipal water distribution
system which consists of 2 deep (1,500 ft) water wells, an
elevated 50,000 gallon water storage tank, a 250,000 gallon on-
ground water storage tank and a reverse osmosis water treatment
plant with a 50,000 gallon clearwell. The Town has experienced
heterotrophic bacterial growth in their wells that has required
extensive rehabilitation work and replacement of one well. This
bacterial growth is starting to build up on a second well and
in several years will become problematic and will require
replacement. This well screen problem is chronic and is on
going. The current groundwater raw water supply is over the
Maximum Contaminant Level (MCL) established in the Safe
Drinking Water Act for fluoride and above the secondary limit
for sodium. The Town of Circle must remove these contaminants
and since conventional treatment processes won't remove
fluoride they must utilize an energy intensive reverse osmosis
treatment process. If the current treatment process has
mechanical problems the Town would be forced to put water into
the distribution system that is a documented health hazard. The
Town of Circle will benefit in the long term by connecting to
the Dry-Redwater. The uncertainty of the life of their wells,
the cost to replace a well (over $150,000) and the cost to
treat the water are all items that strengthen their commitment
to this project.
Town of Jordan
The Town of Jordan has a municipal water distribution system which
consists of 2 water wells and a 200,000 gallon on-ground water storage
reservoir. There is no treatment of the water but it is disinfected by
being chlorinated. The quality of the water exceeds many of the
secondary limits, such as sodium and total dissolved solids, of the
amendments to the 1996 Safe Drinking Water Act. The potential for
increased regulation of the groundwater rule (GWR) and disinfection by
products rule would cause an additional cost to each user in Jordan in
order to be in compliance with the rule. The Town of Jordan will
benefit from the Dry-Redwater project by having a water supply that is
treated to the most current water quality standards and delivered at a
consistent volume and pressure.
Town of Richey
The Town of Richey has a municipal water system that consists of
two deep water wells (1400 ft), an on-ground 100,000 gallon steel
water storage reservoir and a reverse osmosis water treatment facility.
The raw water source for Richey is identical to Circle in that exceeds
the MCL for fluoride and the secondary limits for sodium so that is why
the Town of Richey also utilizes the energy intensive reverse osmosis
treatment process. If the current treatment process has mechanical
problems the Town would be forced to put water into the distribution
system that is a documented health hazard. The water treatment facility
reduces the levels of each contaminant to below the limits. The Town of
Richey will benefit from inclusion in the Dry-Redwater project since
its current raw water source is in violation of the drinking water
standards if not treated and the current system has a fairly high cost
to operate when compared with conventional treatment. The replacement
costs of membranes and increased electrical costs in the future will
also make connecting to the regional system more economical.
Lambert County Water and Sewer District
Lambert County Water and Sewer District has a central water
distribution system. This unincorporated town has two deep water wells
( 1,200 ft), a 50,000 gallon on-ground steel water storage tank and a
nano-filtration (membrane) water treatment facility. The water supply
exceeds the MCL for fluoride and exceeds the secondary limit for sodium
that is why the District utilizes an energy intensive nano-filtration
treatment process. If the current treatment process has mechanical
problems the Town would be forced to put water into the distribution
system that is a documented health hazard. The District will benefit
from connection to the Dry-Redwater for the same reasons as Circle and
Richey.
Fairview
The Town of Fairview draws its water from two wells approximately
240 feet deep. The central distribution system has a 100,000 gallon
elevated water storage tank and a 300,000 gallon on-ground steel water
storage tank. The ground water source is high in tannins, lignens, iron
and manganese. The Town utilizes an iron and manganese removal process
and gas chlorine for disinfection. The Town has recently received a
notice from the Montana Department of Water Quality that they had a
test for haloacetic acids (HAAS) and total trihalomethanes (TTHMs)
(disinfection by product contamination) that exceeded the limits set by
the Safe Drinking Water Act. The Town is now studying and determining
what changes in their disinfection process they need to make to meet
the Disinfection by Products Rule. The high organic content of their
raw water is a significant factor in the creation of the by products.
The Town of Fairview will benefit greatly by receiving its water from
the Dry-Redwater Regional Water Authority system.
New Rural Users--New users would include rural residents who have
not had the opportunity to be connected to a high quality treated
source of water as provided by a regional water system. These residents
use individual wells for domestic and agricultural needs, haul water
from other sources or purchase bottled water for drinking purposes. The
water quality varies greatly throughout the project area but generally
has levels exceeding the U.S. EPA Secondary Health Standards with high
levels of total dissolved solids, hardness, sulfates, sodium, iron,
manganese and areas of high fluoride. The majority of these wells are
constructed in glacial till materials typical of the project area,
resulting in wells which have varying abilities to provide a sufficient
quantity and adequate quality of water supply. The cost to install new
water well has been determined, based on information provided by NRCS,
to be over $90 / month when you factor in the replacement cost of the
various components of a well system. The box below shows how this cost
was determined:
Drill and case well: $35.00/ft average depth 200-250 ft Cost:
$7,000-$8,750
If a well lasts 15 years the monthly cost is $39.00 to 48.00 per
month.
Pump and Motor: $1,000.00 If a pump lasts 5 years the monthly cost
is $16.70.
Control pit/pressure tank: $2,800 with a 15 years life has a
monthly cost of $15.60.
Annual stock well electrical base rate is $240.00 per year or
$20.00/month before electrical use.
The cost to run electricity to a new well site is $17,160.00/mile
or $3.25/ft. This cost was provided by McCone Electric.
For a new well that already has electric service the monthly costs
before any water is pumped is $91.30 to $100.30.
When you have bad groundwater to start with, treatment doesn't
improve its quality, it only reduces some of the chemical components to
meet regulation standards, this does not necessary mean the water is
free from taste and odors. Second, maintaining the individual systems
does not address the benefits of providing a firm water supply that
protects the communities against future drought. The individual user
also relies on a well pump and small pressure tank to provide water,
and when the power is out they lose the ability to access their
domestic water source. The regional system will have storage tanks that
will pressure the system and backup power systems.
From a regulatory aspect a regional water system has significant
benefits. At the present time, there are six different regulated public
water systems within the region that are part of the Authority. Meeting
regulatory requirements of the Safe Drinking Water Act must be
currently demonstrated by each system. When a rule changes, all those
systems must react to the change individually. Many of the systems
serve small municipalities or county water districts, some with fewer
than 150 connections, there is a reduced capacity on their part to
maintain and operate a water system. That means that the Montana
Department of Environmental Quality is perennially facing problems with
compliance issues in these smaller public water systems. A regional
water system would provide one point of regulation for all of the
member systems. If a rule were changed, it would only affect one
treatment plant and due to economies of scale, a regional system can be
upgraded and operated at a higher level of oversight and management at
a smaller per user cost than smaller individual municipal water supply
systems. An increased degree of compliance can be expected from a
regional water system which further assures the water users of a safe
and reliable source of water.
The Project
The effort began in 2002 with a steering committee of volunteers,
with the Dry-Redwater Regional Water Authority becoming a legal entity
in 2005. The Dry-Redwater has enjoyed strong support from the local
people and the State of Montana. Currently about 70% of the households
in the area, have provided letters of support and or have already paid
a `good intention' fee to show their financial commitment. Over $60,000
of locally raised funds have been put toward the project and thousands
of hours of volunteer efforts have helped move the proposed regional
water system forward. The State of Montana thru the Department of
Natural Resources has committed over $400,000 to the studies and
organizational efforts of the project to date. The Montana Department
of Commerce provided $40,000 of CDBG funds and the Federal Economic
Development Administration provided $40,000 used to help pay for the
completed feasibility study. This current investment of over $500,000
does not include the thousands of hours of volunteer time and effort.
The project as conceptualized will consist of 1,220 miles of
pipeline, 38 pump stations and 20 major water storage reservoirs. It is
projected to cost $115,116,000. By working together, the communities in
the area can more efficiently provide affordable safe and reliable
water to people in the project area. The water for this project will be
obtained from the Dry Arm of Fort Peck Lake near Rock Creek. The
water--approximately 3,500 acre feet, of the 18 million acre feet
available--will include a storage lease from the Corp of Engineers. The
in-take and conventional treatment facility will be located at North
Rock Creek on the Dry Arm of Fort Peck Lake. The process to find a
location for the intake facility was done as a joint effort with the
Corp of Engineers and the Charles M. Russell National Wildlife Refuge.
The feasibility study and addendum, completed in 2007, and as well
as significant public participation in over 20 public meetings show
that the need for safe and reliable water is a priority for the area's
residents. The project is financially feasible given the funding
packages used by the rural water systems in Montana and in comparison
to rural water system costs in our three state region of Montana, South
Dakota and North Dakota. The completed feasibility study includes
preliminary engineering analysis of the system. The Dry-Redwater has
also completed some preliminary cultural and environmental reviews.
There are no fatal flaws found in these preliminary studies which
included contacts with State, Federal and Local officials on NEPA
compliance.
The median household income for the service area, from our
feasibility study in 2007, is $28,917 and using a 1.6% factor for
estimating a reasonable cost of water the average monthly rate is
calculated at $38.55. The rates proposed for the Dry-Redwater shows
that utilizing the typical rural water funding package the project is
affordable to the users.
Dry-Redwater has been working closely with the Billings office of
the Bureau of Reclamation (Reclamation) to move the project thru its
brand new process as stipulated in the Rural Water Supply Act of 2006,
and as expressed in the Interim Final Rules. However, given the
investment made in time and money and the fact that the system's
authorization bill was introduced by Senator Baucus in 2008, again in
2009 as old SB 637, and again now as Senate Bill 419, it has been
agreed by the Authority Board and other supporters of the regional
concept that the project must move forward. In 2010 Reclamation finally
provided the Dry-Redwater an outline of the requirements for the
Appraisal Investigation and Report under the Rural Water Supply Act of
2006. The Dry-Redwater Feasibility Study and addendum completed in 2007
will substantially satisfy the requirements ofAppraisal and
Investigation Report as provided by the Reclamation Billings office.
The 2007 Feasibility Report is being augmented and reformatted into
reclamations required format and will be submitted to them by the end
of December 2011. Congressional Authorization is a requirement of this
process and thus this request for Congressional Authorization of the
project is considered the correct and timely process, as the system
planning has reached a point beyond which it cannot easily move
forward, without the ability to work formally with Reclamation, U.S.
Fish and Wildlife and other federal agencies. In addition, the State of
Montana has funds available to help start construction, but the
projects must be federally authorized to access these funds. Senate
Bill 419 Authorization allows Reclamation to make a determination if
the project is feasible prior to any federal funding used for
construction following the guidelines of the Rural Water Act of 2006.
The Engineers that completed our study made the following finding
in our feasibility efforts. ``Based upon preliminary review of the
water quality in the wells of rural users in the proposed service area
it indicated that the majority of them do not have access to a quality
of water needed for a healthy existence.''
Many area residents are not served by any public water system. Due
to the limited availability and poor quality of groundwater, these
residents must haul their own water. The available water supply fails
to meet water quality standards and poses real health risks to the
area's population.
By working together all of the communities in the area can better
provide affordable good quality water to all of the people. Currently,
the primary source of drinking water in our service area is
groundwater. It is generally of very poor quality and quantity. The
drinking water in most groundwater wells in the area exceeds the
secondary standards and in some cases are four times the recommended
EPA standards. Water quality problems are exacerbated by water supply
issues and because of the general lack of good quality groundwater,
most of the area's larger public water systems use expensive energy
intensive treatment methods to produce clean water. The positive health
benefits of good quality drinking water will without a doubt be a
tremendous benefit to the area citizens and to the overall economy of
the region.
Economic Benefits
A dependable supply of water is essential to ongoing efforts to
attract new businesses and people to this primarily agricultural based
frontier area of Montana in order to provide for future economic
growth. In addition to long term benefits, the regional water project
will provide an immediate economic boost for eastern Montana. Assuming
labor costs for the project at 25 percent of the total construction
budget, the project will generate approximately $30 million in wages.
These construction dollars will provide a much needed stimulus to the
regional economy of McCone, Garfield, Dawson, Richland, Prairie
Counties and the statewide economy.
The Dry-Redwater's service area has many natural resources that
could be developed to help the United States become more self reliant
when it comes to energy. The area has tremendous resources in water,
ground to grow crops for bio-fuels, one of the nation's largest on
shore oil reserves in the Bakken Formation Oil Field, the largest
lignite coal reserve in the United States and a huge potential for wind
farm development. There are a number of energy related projects that
have been and are proposed within the Dry-Redwater service territory.
An example is a nationally important oil transmission pipeline known as
the TransCanada Keystone XL project will pass through the area. A good
source of safe and reliable water supply is critical infrastructure to
support the development of any of these nationally important energy
sources.
The regional pipeline will provide one of the key resources that
enterprising businesses and people look for when they locate in an
area-a safe water supply. Ranch/farm operations will benefit from the
stock water available through the system. This will immediately improve
their bottom line, as increased weight gain can be achieved with higher
quality water. Efforts to diversify the agriculturally based economy
with tourism, wildlife enhancement, hunting, fishing, dinosaur
discoveries, outdoor recreation has been somewhat successful but a high
quality water source will help its development to improve recreation
facilities owned by the COE, the State of Montana and the counties of
the Dry-Redwater Service area. This project will not resolve all of the
economic problems that eastern Montana faces; however, it will serve as
a cornerstone to future success upon which the people in the area can
build.
Finally and perhaps most importantly, we believe the health
benefits of safe water will help save the citizens by reducing water
related medical problems and thus decreasing medical costs. A rural
resident L. Taylor from McCone County stated ``that her doctor told her
not to drink their water as they attributed their well water to her
numerous bladder infections''.
Alternate Sources
The Dry-Redwater Regional Water Authority has studied possible
alternatives to supply water to the region. The option of updating the
six existing public water supply systems to comply with the Safe
Drinking Water Act was rejected due to the high cost and multiple water
sources to test and monitor. The use of additional groundwater sources
was also investigated. This option was not feasible because there is
very little groundwater physically available in the quantity needed,
and the groundwater that is available is of very poor quality and would
require an expensive treatment process. Of all the alternatives
reviewed, the proposed regional water project found that utilizing the
high quality surface water found in the upper Missouri River basin
proved to be the best.
The water impounded in Fort Peck Lake provides a very dependable
water supply while offering the lowest capital project and life-cycle
costs to treat and deliver water to the end user. The cooperative
efforts of the USACOE staff at Fort Peck and the staff of the CMRNWR
provided an excellent location for the intake structure that is in a
deep water portion of the lake and will have minimal impacts on the
wildlife found in the refuge.
A water treatment plant, using conventional filtration, will be
located near the intake in the Dry Arm of Fort Peck Lake near North
Rock Creek. The water will be treated to meet both the primary and
secondary requirements of the Safe Drinking Water Act standards. A
series of transmission pipelines will provide water to smaller
distribution lines belonging to the area's public water supply systems
and to the rural users. The regional water system will take advantage
of the infrastructure of the existing distribution systems. When
completed, the regional water system will provide a safe and dependable
water supply for over 15,000 people. Water will be provided to all or
parts of six counties which includes an 11,100 square mile area.
Without the proposed centralized water treatment plant, most of the
participating systems would be required to build new or to
significantly upgrade existing high energy use, water treatment plants
as the Safe Drinking Water Standards are made more stringent. The low
population densities and limited income potential in eastern Montana,
individual communities will not be able to afford own and operate their
own water treatment plants. A central water treatment plant will allow
these existing systems to economically meet both the current and future
requirements of the Safe Drinking Water Act and continue to provide
their users with safe, reliable and affordable water.
The estimated total project cost is $115.1 million. The Bill
proposes the federal share of the construction to not exceed 75
percent. The Dry-Redwater Regional Water Authority will be responsible
for the cost of operating, maintaining and repairing the overall
system.
There are distinct benefits of a regional water system:
Communities will not absorb the costs of upgrading numerous
smaller water facilities to keep up with water quality
standards.
A greater number of regional system users helps defray the
cost of good water for every individual in the area.
This system will provide jobs, not only during construction,
but also for ongoing operation and maintenance.
Economic and community development opportunities with the
ability to attract businesses and people that need a reliable
water source is greatly enhanced.
Total water and energy consumption by all communities will
be substantially less than if each community provides water
treatment.
A dependable, high-quality drinking water sources provides
an incentive for business and industry to consider relocation
to eastern Montana.
Reduction in chemical usage and cost as a result of
increased crop sparying efficiency.
Rural area fire protection capacity
Increased property values
An alternative water sources for livestock.
Safe and reliable household drinking water to improve the
health and existence of the people.
Many people in eastern Montana presently do not have a reliable
source of high quality water. The proposed regional water system will
provide water to an area historically afflicted by water supply and
quality problems. The positive health benefits of safe household
drinking water is critical to the well being of the people of eastern
Montana and will provide the required infrastructure for the regions'
and State's economy. We ask this subcommittee's support in passing this
important legislation to protect the health, social and economic future
of our region.
Thank you again for the opportunity to testify in support of the
Dry-Redwater Regional Water Authority and the passage of Senate Bill
419. I would be pleased to answer any questions.
______
Statement of Mike McKeever, Chairman, Dry-Redwater Regional Water
Authority, State of Montana, on S. 419
Madam Chairman and Members of this Subcommittee,
I am pleased to comment on behalf of the Dry-Redwater Regional
Water Authority and thank you for the opportunity to provide a brief
written testimony in favor of S. 419. This important legislation allows
us to be authorized and eventually provide good, clean, safe water to
nearly 20,000 people in an 11,000 square mile area of Eastern Montana.
Hardly a day goes by that we don't have a sign up or an inquiry on when
the project is ready to lay pipe. This is becoming more evident as the
oil activity increases in Eastern Montana--more people want good,
clean, safe water.
We completed our appraisal study in June of 2010 and that was
accepted by the Bureau of Reclamation. Our request for financial
assistance was accepted and we are currently working with Reclamation
to complete our feasibility study. The path that Reclamation has
provided for us to follow, along with their technical assistance, will
enable us to address their concerns in an acceptable format. Our
feasibility study should be done the last quarter of 2011 and be ready
for review.
Authorization would allow us to continue with the planning, design
and eventual construction of this important infrastructure project in
Eastern Montana. Please consider this as a favorable project for
Montana and vote for S. 419.
Thank You,
______
Statement of Ann C. Pongracz, Senior Deputy Attorney General, Counsel
to the Colorado River Commission of Nevada, on S. 519
My name is Ann C. Pongracz, Senior Deputy Attorney General, and I
serve as Counsel to the Colorado River Commission of Nevada. I
appreciate Senator Harry Reid and Senator Dean Heller for their
leadership on this bill. The Hoover Power Allocation Act of 2011 (S.
519) is very important to the State of Nevada, which is one of the
three lower basin states directly affected by the Hoover power
contracts. The Colorado River Commission of Nevada strongly supports S.
519.
The Colorado River Commission is the state agency charged with,
among other duties, receiving and allocating federal hydropower from
the Colorado River that is provided to the State of Nevada. This
legislation is crucial to my state. On behalf of the State in its
sovereign capacity and also as principal on its own behalf, the
Colorado River Commission receives electric power generated by Hoover
Dam through delivery contracts with the Western Area Power
Administration of the U.S. Department of Energy. The Commission, in
turn, contracts to deliver Hoover power to retail and wholesale
customers in Southern Nevada. We also operate a power delivery system
to deliver this critical resource to our customers.
The Colorado River Commission of Nevada has worked for three years
with representatives of Arizona and California to develop this
consensus approach to ensuring that the benefits of Hoover power will
continue to be delivered to the citizens of our three states after
current contracts expire in 2017.
S. 519 extends current Hoover power contracts for fifty years to
2067. It re-directs five percent of Hoover capacity and associated
energy from current contractors to a resource pool that will be made
available to new allottees in Nevada, Arizona and California who do not
receive any Hoover power today. This bill will allow federally-
recognized Indian tribes to apply to access the dam's power for the
first time, as well as entities eligible under section 5 of the Boulder
Canyon Project Act such as states, municipal corporations and political
subdivisions.
S. 519 provides coordinated Federal/ State management of the new
allottees' resource pool. The Western Area Power Administration will
allocate two-thirds of the pool, and the remaining one-third of the
pool will be distributed in equal shares through the Arizona Power
Authority (for new allottees in Arizona), the Colorado River Commission
of Nevada (for new allottees in Nevada), and Western (for new allottees
in California). S. 519 requires new allottees to pay a proportionate
share of the costs borne today by current contractors for operational
and environmental purposes.
We urge the Congress to approve S. 519. We believe that Congress
should allocate post-2017 Hoover power as it has done since Hoover Dam
was constructed in 1935. Congressional approval is needed to ensure the
continued availability and reliability of Hoover power to the citizens
of Nevada, Arizona and California. The State of Nevada supports S. 519
in its entirety and urges the Committee to approve the bill.
Thank you for the opportunity to submit this statement for the
record. I will also submit support letters from the Nevada customers
who benefit from Hoover power including the Southern Nevada Water
Authority and NV Energy.
______
Statement of Gawain Snow, General Manager, Uintah Water Conservancy
District, S. 808
To direct the Secretary of the Interior to allow for prepayment of
repayment contracts between the United States and the Uintah Water
Conservancy District.
I want to thank Senator Orrin Hatch and Senator Mike Lee for
introducing this bill on behalf of the Uintah Water Conservancy
District (District). The District was formed in 1956 for the purpose of
``conserving, developing and stabilizing supplies of water for
domestic, irrigation, power, manufacturing, municipal and other
beneficial uses, and for the purpose of constructing drainage works.''
The District operates and maintains the Vernal and Jensen Units of the
Central Utah Project, which was authorized by Congress as part of the
Colorado River Storage Project Act of 1956. The District encompasses
almost all of Uintah County, Utah in eastern Utah adjacent to the
border of Colorado.
At the time of its construction (1984-1987), the Jensen Unit was to
provide 18,000 Acre Feet (AF) of M&I water to the residents of Uintah
County. Six thousand AF were to be developed with the construction of
Red Fleet dam (which was built) and another 12,000 AF were to be
developed at a later date with the construction of the Burns Bench Pump
station on the Green River in Jensen, Utah. Due to the economic bust in
the mid to late 80's, the demand for water that had been foreseen was
no longer there. Also, in 1989 an amendatory contract was signed with
the Bureau of Reclamation (Bureau) reducing the amount of water
subscribed to by water providers to 2,000 AF.
The Bureau of Reclamation desires to do a final cost allocation on
the Jensen Unit. Such action would be premature without developing the
remaining 12,000 AF on the Green River, because the cost per acre-foot
would be approximately 2.5 times as much as if the 12,000 AF were
developed. Also, at this time, not all of the 6,000 AF of water in Red
Fleet Dam has been subscribed. A Block Notice was issued to the
District from the Bureau of Reclamation for the 2,000 AF and the
District contracted with the municipalities, water improvement
districts, and a private company for all of that water. Since that time
the additional 4,000 AF of M&I water remains unsubscribed. The Bureau
of Reclamation took 700 AF to increase the conservation pool in the
reservoir leaving 3,300 AF of available water in Red Fleet Dam. The
Burns Bench pump station will not be constructed until all of the M&I
water available in Red Fleet is subscribed. In the past year, the
District has received several inquiries for the remaining M&I water in
Red Fleet but no contracts have been signed. The price of the water is
set by the amendatory contract. The amount per acre-foot was based on
the cost of the Jensen Unit (including an estimated cost of the pump
station) divided by 18,000 AF. The resulting cost is $5,555.21 per
acre-foot and is payable by dividing that amount by the number of years
remaining until 2037 with the last payment being made in 2037. Water
purchased in 2006 would be paid for at a rate of $179.07 per acre-foot
per year for 31 years. The District approached the Bureau of
Reclamation about the possibility of discounting those payments at
either the 3.222% rate, which is used by the Bureau to calculate the
repayment, or the federal funds rate, which is determined at the time
of the discounting. However, according to the Bureau, the amendatory
contract does not allow for prepayment. The District then determined
that it would seek legislation similar to a bill that was used by the
Central Utah Water Conservancy District, which allowed for prepayment
of the repayment contracts for the Bonneville Unit. Prepayment of our
contract with the Bureau will substantially reduce the cost of water to
the District. S. 808 will also produce a substantial payment to the
federal treasury, which we estimate to be between $4-5 million.
S. 808 directs the Secretary of the Interior to allow for
prepayment of the specified contracts and amendments to them between
the United States and the Uintah Water Conservancy District providing
for repayment of municipal and industrial water delivery facilities
under terms and conditions similar to those used in implementing
provisions of the Central Utah Project Completion Act. It also provides
that the prepayment: (1) may be provided in several installments to
reflect substantial completion of the delivery facilities being
prepaid; (2) shall be adjusted to conform to a final cost allocation;
and (3) may not be adjusted on the basis of the type of prepayment
financing utilized by the District.
Again I want to thank you for the opportunity to testify today and
will be happy to respond to any questions.
______
Federal Energy Regulatory Commission,
Washington, DC, May 18, 2011.
Hon. Jeff Bingaman,
Chairman, Committee on Energy and Natural Resources, 304 Dirksen Senate
Office Bldg., Washington DC.
Re. S. 334
Dear Chairman Bingaman: This letter is in response to your request
for my views on S. 334. That bill would require the Federal Energy
Regulatory Commission to reinstate the license for the proposed 1.5-
megawatt Lateral 993 Hydroelectric Project No. 12423, to be located at
the juncture of the 993 Lateral Canal and the North Gooding Main Canal,
northwest of the town of Shoshone, in Lincoln County, Idaho. The bill
also would require the Commission to extend the commencement of
construction deadline for the project to September 25, 3013.
The Commission issued an original license for this project, to
American Falls Reservoir District No. 2 and Big Wood Canal, on
September 26, 2003. The license provided that the company was required
to commence project construction within two years of the date of the
license, the maximum period permitted by section 13 of the Federal
Power Act. The Commission subsequently granted a two-year extension of
the commencement of construction deadline, again the maximum authorized
by section 13, Construction had not commenced when that deadline
expired, on September 26, 2007. Section 13 provides that, when
construction has not timely commenced, the Commission must terminate
the license. The Commission terminated the license by order dated
August 3, 2009.
I and the last several Commission Chairmen have taken the position
of not opposing legislation that would extend the commencement of
construction deadline no further than 10 years from the date that the
license in question was issued. Where proposed extensions would run
beyond that time, there has been a sense that the public interest is
better served by releasing the site for other public uses. Because S.
334 requires the Commission to an extension to September 25, 2013, thus
extending the commencement of construction deadline to 10 years from
when the license was issued, I do not oppose the bill.
If I can be of further assistance to you on this or any other
Commission matter, please let me know.
Sincerely,
Jon Wellinghoff,
Chairman.
______
Federal Energy Regulatory Commission,
Washington, DC, May 18, 2011.
Hon. Jeff Bingaman,
Chairman, Committee on Energy and Natural Resources, 304 Dirksen Senate
Office Bldg., Washington, DC.
Re: S. 333
Dear Chairman Bingaman: This letter is in response to your request
for my views on S. 333. That bill would require the Federal Energy
Regulatory Commission to grant a three-year extension of the
commencement of construction deadline for the proposed 1.5-megawatt
Little Wood River Ranch II Hydroelectric Project No. 12063, to be
located on the Little Wood River, near the town of Shoshone, in Lincoln
County, Idaho, and to reinstate the project license if necessary.
The commission issued an original license for this project, to
William Arkoosh, on March 17, 2006. The license provided that the
company was required to commence project construction within two years
of the date of the license, the maximum period permitted by section 13
of the Federal Power Act. The Commission subsequently granted a two-
year extension of the commencement of construction deadline, again the
maximum authorized by section 13. Construction had not commenced when
that deadline expired, on March 16, 2010. Section 13 provides that,
when construction has not timely commenced, the Commission must
terminate the license. The Commission issued an order terminating the
license on February 8, 2011.
I and the last several Commission Chairmen have taken the position
of not opposing legislation that would extend the commencement of
construction deadline no further than 10 years from the date that the
license in question was issued. Where proposed extensions would run
beyond that time, there has been a sense that the public interest is
better served by releasing the site for other public uses. Because S.
333 requires the Commission to grant a three-year extension from the
date of the bill's enactment, thus (assuming enactment during this
session of Congress) extending the commencement of construction
deadline to less than 10 years from when the license was issued, I do
not oppose the bill.
If I can be of further assistance to you on this or any other
Commission matter, please let me know.
Sincerely,
Jon Wellinghoff,
Chairman.