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67–863 PDF 2011

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 
(II) 

COMMITTEE ON ENERGY AND NATURAL RESOURCES 

JEFF BINGAMAN, New Mexico, Chairman 

RON WYDEN, Oregon 

TIM JOHNSON, South Dakota 

MARY L. LANDRIEU, Louisiana 

MARIA CANTWELL, Washington 

BERNARD SANDERS, Vermont 

DEBBIE STABENOW, Michigan 

MARK UDALL, Colorado 

JEANNE SHAHEEN, New Hampshire 

AL FRANKEN, Minnesota 

JOE MANCHIN, III, West Virginia 

CHRISTOPHER A. COONS, Delaware 

LISA MURKOWSKI, Alaska 

JOHN BARRASSO, Wyoming 

JAMES E. RISCH, Idaho 

MIKE LEE, Utah 

RAND PAUL, Kentucky 

DANIEL COATS, Indiana 

ROB PORTMAN, Ohio 

JOHN HOEVEN, North Dakota 

BOB CORKER, Tennessee 

ROBERT M. SIMON, Staff Director 

SAM E. FOWLER, Chief Counsel 

MCKIE CAMPBELL, Republican Staff Director 

KAREN K. BILLUPS, Republican Chief Counsel 

SUBCOMMITTEE ON WATER AND POWER

JEANNE SHAHEEN, New Hampshire, Chairman 

RON WYDEN, Oregon 

TIM JOHNSON, South Dakota 

MARIA CANTWELL, Washington 

BERNARD SANDERS, Vermont 

DEBBIE STABENOW, Michigan 

JOE MANCHIN, III, West Virginia 

MIKE LEE, Utah, Ranking 

JAMES E. RISCH, Idaho 

DANIEL COATS, Indiana 

JOHN HOEVEN, North Dakota 

BOB CORKER, Tennessee 

JEFF BINGAMAN and LISA MURKOWSKI are Ex Officio Members of the Subcommittee 
(III) 

C O N T E N T S 

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 

(1) 

WATER AND POWER BILLS 

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 
2 

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 DryRedwater 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. 
3 

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:] 
4 

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 Sys-
5 

tem 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 allo-
6 

1This allocation will be subject to revision should there be additions to the project. 

cated to the contracted 2,000 acre-feet in order to achieve a full and final project 

repayment.1

These are the costs that paragraph 3 of S. 808 requires to be included in the pre- payment. 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 mid2010 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 Serv-
7 

1Mni Wiconi Project (SD), PSMB/Garrison Diversion Project (ND), Forest Peck Reservation/ 

Dry Prairie Rural Water System (MT), Rocky Boy’s/North Central 

ice 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. 

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. 
8 

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 
9 

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 hydrodevelopment 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 
10 

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. 
11 

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 pe-
12 

riod 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. 
13 

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. 
14 

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 hydrogeneration. 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 com-
15 

prised 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—— 
16 

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? 
17 

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 
18 

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 
19 

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. 
20 

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. 
21 

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 be-
22 

lieve—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.] 
(23) 

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. § 

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. § 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. 
24 

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. 
25 

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 marketbased 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. 

(27) 

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 usersnot 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. 
28 

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. 
29 

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. 
30 

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 (DRYREDWATER), 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 DryRedwater 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 DryRedwater 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 
31 

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 
32 

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. 
33 

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 nanofiltration 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 DryRedwater 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 
34 

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 DryRedwater Regional Water Authority becoming a legal entity in 2005. The DryRedwater 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. 
35 

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 DryRedwater 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 drink-
36 

ing 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 Drink-
37 

ing 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, 
38 

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 federallyrecognized 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. 
39 

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 acrefoot 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 
40 

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. 

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