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36–883 PDF 2007

S. HRG. 110–97

LAVERTY AND KELLIHER NOMINATIONS

HEARING

BEFORE THE

COMMITTEE ON 

ENERGY AND NATURAL RESOURCES 

UNITED STATES SENATE

ONE HUNDRED TENTH CONGRESS

FIRST SESSION

ON

THE NOMINATIONS OF JOSEPH T. KELLIHER TO BE A MEMBER OF THE 

FEDERAL ENERGY REGULATORY COMMISSION AND R. LYLE LAVERTY 

TO BE THE ASSISTANT SECRETARY FOR FISH, WILDLIFE AND PARKS, 

DEPARTMENT OF THE INTERIOR

MAY 10, 2007

(

Printed for the use of the 

Committee on Energy and Natural Resources 
(II)

COMMITTEE ON ENERGY AND NATURAL RESOURCES 

JEFF BINGAMAN, New Mexico, Chairman

DANIEL K. AKAKA, Hawaii 

BYRON L. DORGAN, North Dakota 

RON WYDEN, Oregon 

TIM JOHNSON, South Dakota 

MARY L. LANDRIEU, Louisiana 

MARIA CANTWELL, Washington 

KEN SALAZAR, Colorado 

ROBERT MENENDEZ, New Jersey 

BLANCHE L. LINCOLN, Arkansas 

BERNARD SANDERS, Vermont 

JON TESTER, Montana 

PETE V. DOMENICI, New Mexico 

LARRY E. CRAIG, Idaho 

CRAIG THOMAS, Wyoming 

LISA MURKOWSKI, Alaska 

RICHARD BURR, North Carolina 

JIM DEMINT, South Carolina 

BOB CORKER, Tennessee 

JEFF SESSIONS, Alabama 

GORDON H. SMITH, Oregon 

JIM BUNNING, Kentucky 

MEL MARTINEZ, Florida

ROBERT M. SIMON, Staff Director 

SAM E. FOWLER, Chief Counsel 

FRANK MACCHIAROLA, Republican Staff Director 

JUDITH K. PENSABENE, Republican Chief Counsel 
(III)

C O N T E N T S 

STATEMENTS 

Page

Allard, Hon. Wayne, U.S. Senator from Colorado ................................................. 2

Bingaman, Hon. Jeff, U.S. Senator from New Mexico .......................................... 1

Domenici, Hon. Pete V., U.S. Senator from New Mexico ..................................... 1

Kelliher, Joseph T., Nominee to be a Member of the Federal Energy Regulatory Commission ............................................................................................... 8

Laverty, R. Lyle, Nominee to be the Assistant Secretary for Fish, Wildlife 

and Parks, Department of the Interior .............................................................. 5

Salazar, Hon. Ken, U.S. Senator from Colorado ................................................... 3

APPENDIX 

APPENDIX I 

Responses to additional questions .......................................................................... 43

APPENDIX II 

Additional material submitted for the record ........................................................ 123

(1)

LAVERTY AND KELLIHER NOMINATIONS 

THURSDAY, MAY 10, 2007

U.S. SENATE, COMMITTEE ON ENERGY AND NATURAL RESOURCES, Washington, DC. 

The committee met, pursuant to notice, at 9:33 a.m., in room 

SD–366, Dirksen Senate Office Building, Hon. Jeff Bingaman, 

chairman, presiding. 

STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM 

NEW MEXICO 

The CHAIRMAN. All right, why don’t we get started? Let me just 

alert everyone that we’ve been told there’s a vote at 9:55. We would 

like to try to proceed with the hearing, and get everybody’s statement in and at least some questions, and hopefully conclude things 

before we all have to go to the floor and vote. 

The hearing today is on the nomination of Joseph T. Kelliher to 

a second term on the Federal Energy Regulatory Commission, and 

the nomination of R. Lyle Laverty to be the Assistant Secretary for 

Fish, Wildlife and Parks at the Department of the Interior. 

Mr. Kelliher is currently the Chairman of the Federal Energy 

Regulatory Commission. The committee favorably reported and the 

Senate confirmed his previous nomination to the Commission in 

2003. The President designated him as Chairman in July 2005. 

Mr. Laverty is a professional forester who served as Regional 

Forester in the Rocky Mountain Region, and Associate Deputy 

Chief of the U.S. Forest Service. For the past 5 years, he’s been the 

Director of Colorado’s State Parks. 

We’re very pleased to have both nominees before the committee 

today to consider their nominations. Let me call on Senator 

Domenici at this point for any comments he has. 

STATEMENT OF HON. PETE V. DOMENICI, U.S. SENATOR FROM 

NEW MEXICO 

Senator DOMENICI. Mr. Chairman, considering the time constraints, I would ask that my comments be made a part of the 

record, as if read. I’ll merely say to the two nominees, I wish you 

the very best, and we know of your ability to perform, and we look 

forward to you performing well for the people of our country in this 

capacity. One, you’ve already done it before—just keep doing it; the 

other one, in your new capacity, we wish you well. 

Thank you very much, Mr. Chairman. 

[The prepared statement of Senator Domenici follows:]
2

PREPARED STATEMENT OF HON. PETE V. DOMENICI, U.S. SENATOR FROM

NEW MEXICO

Good morning. I want to welcome the nominees and their families to the Committee today. I also thank Senator Bingaman for scheduling this hearing this morning to consider the President’s nominees for these two very important positions. 

Just over eighteen months ago, the President signed into law the landmark Energy Policy Act of 2005. The Members of this Committee worked very hard throughout the process of getting that legislation enacted to ensure that its electricity and 

natural gas provisions were sound policy for the nation. 

Most of those provisions required implementation by the Federal Energy Regulatory Commission. I just want to note that I have been very pleased with the speed 

with which the FERC has implemented the bill under Mr. Kelliher’s direction as 

Chairman. His nomination for another term is indicative of the confidence many 

people have in him, his grasp of the issues, and his leadership skills. 

Of similar importance to many of us on this Committee is the position for which 

Mr. Laverty has been nominated. The national parks are some of the country’s 

greatest natural treasures. And the interface between the Endangered Species Act 

and almost every other issue related to development of our energy and water resources is critical to our crafting balanced national polices on all of those fronts. 

I applaud the willingness of each of you to dedicate yourselves to public service. 

I hope that we’ll be able to move your nomination process along expeditiously.

The CHAIRMAN. All right, thank you very much. 

We have Senator Allard here, and of course, a valued member of 

our committee, Senator Salazar, both to introduce Mr. Laverty. Let 

me call on Senator Allard first. 

STATEMENT OF HON. WAYNE ALLARD, U.S. SENATOR

FROM COLORADO 

Senator ALLARD. Thank you very much, Mr. Chairman, and 

ranking member Domenici, for allowing me the opportunity to 

share my comments here today, and for your leadership on the 

committee. You’re both strong supporters of our Nation’s public 

lands, and I commend you for your efforts, and I believe that one 

of the best ways to support our public lands is to put good, capable 

people in positions to manage them. 

Today, your committee will consider the nomination of Lyle 

Laverty, who I think is one of the most impressive candidates for 

this committee to have had an opportunity to consider, to serve in 

the Department of the Interior. Mr. Laverty is nominated to be Assistant Secretary for Fish and Wildlife and Parks at the Department of the Interior. I can think of no one better-suited to fill this 

role than Mr. Laverty. 

I have had the pleasure of knowing Lyle for a number of years, 

and I have had the opportunity to see his good work up close in 

my home State of Colorado. Since 2001, he’s served as director of 

Colorado State Parks, and in this capacity, opened several new 

State Parks, successfully worked to increase park visitation, reduce 

the threat of wildfire on State lands, has helped put Colorado State 

Parks in excellent condition. 

Before coming to Colorado, Mr. Laverty displayed a high degree 

of dedication and leadership with 35 impressive years of service to 

the U.S. Forest Service. During this time, he rose through the 

ranks to become Associate Deputy Chief of the Forest Service 

where he helped implement the National Fire Plan. 

Throughout his distinguished career, Mr. Laverty has consistently displayed a commitment to our Nation’s lands, and exceptional leadership. The United States would be fortunate to have 
3

Lyle Laverty as Assistant Secretary for Fish and Wildlife and 

Parks. I have great confidence in Lyle’s abilities, and proudly give 

him my highest endorsement. 

Thank you, Mr. Chairman. 

The CHAIRMAN. Well, thank you very much for your strong endorsement. Let me call on Senator Salazar for any comment he 

would have by way of introduction of the nominee. 

STATEMENT OF HON. KEN SALAZAR, U.S. SENATOR

FROM COLORADO 

Senator SALAZAR. Thank you very much, Chairman Bingaman, 

and Senator Domenici, and thank you, as well, to my colleague, 

Senator Allard, with whom I had breakfast yesterday, and breakfast again yet this morning. It seems we’re hanging around a lot 

together, doing good things for Colorado. 

Let me just say a quick word about Lyle Laverty. First, I have 

known his work closely through his leadership with the Division of 

Parks and Outdoor Recreation for the State of Colorado. At one 

time, in my past, I was the executive director of the Department 

of National Resources, and I oversaw that Division. And there are 

over 40 State Parks in Colorado, and under the stewardship of Lyle 

Laverty, he led our State Parks to a position of prominence in our 

State, and we in Colorado are very proud of his contributions there. 

Second, his work, historically, with the Forest Service where he 

oversaw the management of millions upon millions of acres of our 

Forest Service lands, and it’s something that we are very proud of, 

and the record he established there is something that we’re proud 

of. 

Third, little-known to some people, but known to the members of 

this committee, certainly, the Land and Water Conservation Fund, 

in the State-side part of the Land and Water Conservation Fund, 

over the years Lyle Laverty has been a great advocate of that program. Last year from this committee moved forward in opening up 

Lease Sale 181, in the part of the gulf coast, and the creation of 

the permanent royalty for the Land and Water Conservation Fund. 

Lyle and his associates were very helpful in helping us move that 

forward. 

So, I have full confidence that he will be a strong and effective 

Assistant Secretary for Fish, Wildlife and Parks, and it’s my honor 

to introduce him to the committee here, today. 

The CHAIRMAN. Well, thank you very much for your strong endorsement of the nominee, as well. 

At this point let me just ask the two nominees to come forward, 

and we’ll go through the requirements here. The rules of the committee, that apply to all nominees, require that they be sworn in 

connection with their testimony. I’d ask that each of you stand and 

raise your right hand, please. 

Do you solemnly swear that the testimony that you’re about to 

give to the Senate Committee on Energy and Natural Resources 

shall be the truth, the whole truth, and nothing but the truth? 

Mr. LAVERTY. I do. 

Mr. KELLIHER. I do. 

The CHAIRMAN. Please be seated. 
4

Before you begin your statement, I need to ask three questions 

of each nominee that appears before this committee. Let me ask 

the question, and then ask for a response by each of you. 

No. 1, will you be available to appear before this committee and 

other congressional committees to represent Departmental positions and to respond to issues of concern to the Congress? 

Mr. Laverty. 

Mr. LAVERTY. I will, sir. 

The CHAIRMAN. Mr. Kelliher. 

Mr. KELLIHER. I will. 

The CHAIRMAN. Second question: are you aware of any personal 

holdings, investments, or interests that could constitute a conflict 

of interest or create the appearance of such a conflict, should you 

be confirmed, and assume the office to which you’ve been nominated by the President, Mr. Laverty? 

Mr. LAVERTY. I’m sorry, oh, I’m——

The CHAIRMAN. I think you’re supposed to tell me that you are 

not aware of any personal holdings. 

[Laughter.] 

Mr. LAVERTY. I’m not aware, yes, sir, I had to get down to the 

right paragraph here. 

[Laughter.] 

The CHAIRMAN. All right. 

Mr. LAVERTY. I am not aware of any problems. My investments, 

personal holdings and other interests have been reviewed by myself 

and the appropriate Ethics Counselor within the Department, and 

I’ve taken the appropriate action to avoid any conflicts of interest, 

and there are no conflicts of interest, or appearances thereof, to my 

knowledge. 

The CHAIRMAN. All right, thank you. 

Mr. Kelliher. 

Mr. KELLIHER. My investments, personal holdings, and other interests have been reviewed both by myself, and appropriate Ethics 

Counselors within the Federal Government, I’ve taken appropriate 

action to avoid any conflicts of interest, there are no conflicts of interest, or appearances thereof, to my knowledge. 

The CHAIRMAN. Well, thank you very much. 

The third question for each of you is: are you involved, or do you 

have any assets held, in a blind trust? 

Mr. Laverty. 

Mr. LAVERTY. No, sir. 

The CHAIRMAN. Mr. Kelliher. 

Mr. KELLIHER. No. 

The CHAIRMAN. All right, let me invite each nominee now to introduce any family members that you have here that you have 

brought with you, if you’d like to do that. Mr. Laverty, go ahead. 

Mr. LAVERTY. Thank you, Mr. Chairman. I’d like to introduce my 

wife, Pam, and my sister and brother-in-law, Helen and Dan 

Starrett. 

The CHAIRMAN. We welcome them. Thank you for coming today. 

Mr. Kelliher. 

Mr. KELLIHER. Mr. Chairman, I’d like to introduce my wife, 

Karen, who is from Glenwood, right up the road from your home 

town of Silver City. Also, in her lap, is little Damien, our youngest 
5

child, this is his first Senate hearing so I can’t promise anything 

about his behavior; he’s not sure of the decorum that’s expected in 

these kind of situations. 

[Laughter.] 

Mr. KELLIHER. And next to him is my daughter—our daughter, 

Nora, then our son Aidan, then my father, Joseph, and in the blue 

jacket, my mother, Joan Kelliher. 

The CHAIRMAN. All right, well, we welcome all of you here. 

Thank you for coming. 

At this point, let me just ask a couple of questions, and then 

defer to—well, I guess first we have the statements, I apologize for 

that. 

Go ahead, Mr. Laverty, why don’t you give us the essence of your 

statement. You don’t need to read it all; we will include it in the 

record, of course, as if read. 

TESTIMONY OF R. LYLE LAVERTY, NOMINEE TO BE THE ASSISTANT SECRETARY FOR FISH, WILDLIFE AND PARKS, DEPARTMENT OF THE INTERIOR 

Mr. LAVERTY. Thank you, Mr. Chairman, Senator Domenici, 

members of the committee, it’s truly an honor for me to join you 

here this morning, as I seek your confirmation to become the Assistant Secretary of the Interior for Fish, Wildlife and Parks. 

As a career resource manager and a long-term public servant, I 

find this to be an incredible opportunity to be entrusted with the 

stewardships of two of the icons of America’s heritage. I want to 

thank both the President, and Secretary Kempthorne for their confidence that they’ve shown in me through my nomination. 

My personal connection with America’s great outdoors really begins about 60 years ago in Montana. When—being born and raised 

in California, we traveled with the family to Missoula, Montana to 

visit grandparents, aunts and uncles. I have these vivid memories 

of those experiences. I remember the excitement of catching my 

first trout, I remember waking up in Yellowstone with my grandmother chasing bears out of our campsites, beating on a big metal 

pot. I remember setting up our tent on the floor of Yosemite, and 

I remember those interpretive programs, the fire fall, experiences 

that were just lasting connections that created what I believe is 

this imprint on who I am, and my being. 

I began my professional journey about 4 decades ago, in Northern California. It was to a remote Ranger station on the Klamath 

River that I brought my bride, Pam, who has shared these incredible memories with me for—over the past 4 decades. Our two children, Lori and Chad, experienced life on a Ranger station, and 

grew up as we moved around this great country. 

Throughout my career, I’ve been a practitioner of what I would 

call science, policy and resource capacity in a multitude of project 

and program decision responsibilities. My leadership assignments 

have provided me with the foundation of practical field operations, 

and also a rich understanding of the importance of sound public resource policy. 

I was asked to lead a team that responded to the 1999 GAO report, identifying the need for an integrated strategy to address hazardous fuel conditions on National Forest Lands. Subsequent to 
6

that, I became the Associate Deputy Chief who led the implementation of the National Fire Plan Program that was supported very 

strongly by the Congress. 

In late 2001, I accepted the position as director of Colorado State 

Parks. The unique thing about Colorado State Parks that’s different than most State Park systems in the country—more than 85 

percent of the Division’s operating budget comes from revenue 

other than General Fund. In 2002, we commissioned an assessment 

by PricewaterhouseCoopers to look at how we could better define 

who uses Colorado State Parks, and how people felt about the services, and perhaps, most importantly, how they felt about fees. I 

have a personal connection with the importance of fees and service. 

The relationships I have developed over the years, has resulted 

in great support for my nominations from a variety of organizations 

across the country. You all have a copy of my professional background, so let me focus just a little bit on the position of the Assistant Secretary of Fish, Wildlife and Parks. 

Having spoken with many of you personally, I’m very, very 

aware of many of your concerns about the position and the responsibilities that come with that position. An important part of this 

position, I believe, is to distinguish between questions of science, 

and questions of policy. With my resource background, I am deeply 

committed to ensuring that scientific integrity is maintained, and 

that scientific determinations are accurately and clearly communicated to policymakers. 

My leadership style is built on the foundation of integrity. Integrity demands transparency, integrity is about trust, and trust is 

doing what you said you would do. 

When I met with Senator Wyden, he asked me what I would do. 

Let me share with you some things that I will do. 

If confirmed, the very first day I will meet with the Ethics Officer, following the pattern that Secretary Kempthorne established. 

Second, I’ll meet with the Solicitor’s Office to brief the Office of 

the Assistant Secretary on the rules and regulations with regard 

to the protection and disclosure of information received by that office. I will affirm that decision with a letter to the staff and employees of both agencies, reiterating my personal commitment to 

ethical standards, and my promise to consistently demonstrate the 

transparency I just shared with you. 

Third, I will ensure that my staff understands the difference between questions of science, and questions of policy. As a former 

Federal career employee, I understand the importance of maintaining scientific integrity during the decisionmaking process. I believe 

I was asked to take this position by Secretary Kempthorne, because 

he knows the kind of person that I am, and I am willing to perform 

in that capacity. 

Fourth, I will establish an open-door policy with both the Director of Fish and Wildlife Service, and the National Park Service. 

The first time I’m aware of—if I am confirmed—there will be three 

career professionals in leadership roles in that organization. I am 

excited about working with that kind of a leadership team, where 

we can have that kind of capacity. 

Last, I will establish a code of conduct for my Office that requires 

that everyone—everyone under my supervision, both career and po-
7

litical appointees—treat people, both inside and outside of the Department, with dignity and respect. 

Finally, I want to commit to work collaboratively with all of you 

about what this position is about. I want each of you to know, that 

you or your staff can call me personally, if you determine any concerns whatsoever about the ethical conduct of either me, or any of 

my folks in that organization. 

Thank you, Mr. Chairman, members of the committee, I am, 

again, honored to be in front of you, and I look forward to engaging 

in any questions you might have for me. 

[The prepared statement of Mr. Laverty follows:] 

PREPARED STATEMENT OF R. LYLE LAVERTY, NOMINEE TO BE ASSISTANT SECRETARY

FOR FISH, WILDLIFE AND PARKS, DEPARTMENT OF THE INTERIOR

Mr. Chairman, Senator Domenici, Members of the Committee, I am truly honored 

to join you today as I seek your confirmation to become the Assistant Secretary of 

Interior for Fish, Wildlife and Parks. As a career resource manager and public servant, the opportunity to be entrusted with the care and stewardship of the icons of 

America’s heritage, is the ultimate experience. I want to thank both President Bush 

and Secretary Kempthorne for their confidence in me shown through my nomination. 

My personal connection with America’s great outdoors begins in Montana nearly 

60 years ago. Born and raised in California, I have vivid memories of our family 

journeys to Montana to visit my grandparents, aunts, uncles, and cousins in Missoula. I remember to this day catching my first trout. I remember waking up in Yellowstone as my grandmother chased bears out of our campsite, beating a big metal 

pot. I remember helping my dad set up our tent in the floor of Yosemite. I remember 

the ranger hikes. I remember watching the ‘‘firefall’’ during the evening interpretative programs. Little did I realize that these personal connections created a lasting 

imprint on my being, my inner soul. 

I began my professional journey over 4 decades ago in Orleans, California, a small 

rural mountain community. It was to this remote ranger station on the Klamath 

River, that I brought my bride, who has shared a wonderful journey with me for 

these past four decades. Our two children experienced life on a ranger station as 

we moved throughout this great country. I have worked across the country as a 35 

year career employee with the U.S. Forest Service, and most recently as the Director of Colorado State Parks. 

Throughout my career, I have been a practitioner of science, policy and resource 

capacity in a multitude of project and program decision responsibilities. My leadership assignments over these past four decades have provided me with the foundation of practical field operations and a rich understanding of the structural importance of sound public resource policy. 

I was asked to lead a team to respond to the 1999 GAO Report identifying the 

need for an integrated strategy to address the hazardous fuel conditions on National 

Forest lands. The strategy became the foundation for the National Fire Plan, funded 

by the Congress after the catastrophic fire season in 2000. I was subsequently asked 

to lead the agency’s implementation of the National Fire Plan and did so through 

2001. 

Late in 2001, I accepted the position of Director of Colorado State Parks. The Colorado State Park system is different than most state park systems in America. More 

than 85 percent of the division’s operating budget comes from revenue other than 

general fund. 

In 2002, we commissioned a market assessment of Colorado State Parks. We contracted with PriceWaterhouseCoopers to conduct this assessment. Through this assessment we were able to develop a better definition of who used Colorado State 

Parks, how they felt about the services, and perhaps most importantly, how they 

felt about fees. 

Additionally, we were able to determine who didn’t use our parks and why. Based 

on this foundation we developed a strategic plan for the division, a plan build on 

community conversations in every corner of Colorado. From the ideas Coloradans 

shared with us, we developed an investment strategy, an investment strategy built 

on principles and business plans that would lead us to financially sound park operations. 
8

Given my broad and extensive resource background, I bring a set of qualifications, 

experiences and insights that will add value to an excellent team of professional resource managers. Over the course of my career I have worked with individuals, volunteers, organizations, state agencies and numerous federal agencies. The relationships I have developed over these years have resulted in the support of my nomination by a wide variety of organizations across the country. 

I have a Bachelor of Science in Forest Management from Humboldt State University in Arcata, California, and a Master in Public Administration from George 

Mason University in Fairfax, Virginia. 

My career has afforded me the opportunity to work in a variety of communities 

across this great nation, in the Douglas fir forests of northern California, the Cascades of Oregon and Washington, the Southern portion of California’s Costal Range, 

and the great Rocky Mountains in the Intermountain west. I have found throughout 

these experiences people care deeply about America’s resources. I have worked on 

the ground with a variety of resource projects and served in senior policy positions 

as well. I was intimately involved in the implementation of the National Fire Plan 

and enjoyed the opportunity to work with many of you in that endeavor. 

I have participated in a number of projects working towards the recovery of endangered species. As Regional Forester, I was actively engaged in working with the 

U.S. Fish and Wildlife Service on the recovery of the lynx in Colorado. Ten years 

ago I served on the Interagency Grizzly Bear Committee, coordinating agency activities to support the recovery of the grizzly. As Forest Supervisor of the Mendocino 

National Forest, I worked closely with the U.S. Fish and Wildlife staff and the California Division of Fish and Game in managing the complex southern portion of the 

spotted owl habitat. As the Director of State Parks, with the Fish and Wildlife staff 

and Colorado Division of Wildlife staff, we designed an implemented successful wild 

land fire mitigation project in lynx habitat in the Front Range Colorado. 

In my capacity as Director of Recreation, Heritage, and Wilderness Resource, both 

in the Pacific Northwest Regional Office as well as the National Headquarters of 

the Forest Service, I experienced the challenges of managing natural resource setting for quality visitor experiences. 

Mr. Chairman and members of the Committee, I am aware of the challenges and 

unique opportunities associated with position. I am committed to work closely with 

you to provide the oversight and stewardship of the resources entrusted to me in 

this position. 

Thank you Mr. Chairman and Members of the Committee for considering my 

qualifications supporting my nomination. I will be happy to answer any questions 

you may have.

The CHAIRMAN. Thank you very much. 

Mr. Kelliher, go right ahead. 

TESTIMONY OF JOSEPH T. KELLIHER, NOMINEE TO BE A MEMBER OF THE FEDERAL ENERGY REGULATORY COMMISSION 

Mr. KELLIHER. Thank you, Mr. Chairman. 

Chairman Bingaman, Senator Domenici, and distinguished members of the committee, I am honored to be here today as a nominee 

to be a member of the Federal Energy Regulatory Commission. I 

want to thank Chairman Bingaman for scheduling this hearing, I 

want to express my appreciation to President Bush for nominating 

me to this post, and I want to thank my wife, Karen, for allowing 

me to try to continue doing a job that I love. 

Much of my work as FERC Chairman has been dominated by implementation of the Energy Policy Act of 2005. I want to applaud 

the committee for writing such a good law. You gave FERC the 

tools it needed to protect the public, and strengthen our energy infrastructure, and we are using them in a careful and disciplined 

manner. 

FERC has been very diligent in implementation of the Energy 

Policy Act. We’ve met every deadline you’ve set for us, and very few 

of the rules and orders that we issued were challenged in court, 

and I’m proud of our work implementing the Energy Policy Act. 
9

Perhaps the best way to share my perspective with you is to discuss what I see as the Commissions five principal missions—some 

of which are new, and some of which have changed over time. 

The primary task of the Commission is to guard the consumer 

from exploitation by non-competitive power and gas companies. 

The way FERC has discharged that responsibility has changed over 

time. FERC now relies on a mix of regulation and competition to 

protect consumers. 

I’m proud of the record of the Commission in the past 2 years 

of enacting reforms to strengthen competition and protect consumers. We’ve reformed our open access rules to provide more perfect transmission access and improve transmission planning, we’re 

strengthening our market-based rate program, and we initiated a 

generic review of competition and wholesale power markets, designed to make these markets more competitive. 

We also adopted reforms to increase customer access to renewable sources of energy. We recently adopted California’s proposal to 

facilitate renewable energy development, by reforming our interconnection pricing policies. 

We’ve also adopted reforms relating to natural gas markets. To 

guard against price volatility, we issued rules to encourage greater 

investment in gas storage, and last month, we issued a rule to increase gas market transparency. 

Strengthening our energy infrastructure has also been a central 

Agency mission since 1920. FERC has proved very efficient in this 

role. Since the year 2000, the Commission has approved more than 

9,400 miles of new interstate natural gas pipelines. And, by improving pipeline takeaway capacity, we have promoted the surge of 

gas production in the Rocky Mountains. We also removed barriers 

to pipeline additions that raise no significant environmental issues. 

We’re also acting to strengthen the power grid. 

We issued final transmission siting rules, consistent with Congressional intent in the Energy Policy Act, recognizing that States 

remain the primary siting body for transmission facilities, and that 

the FERC role is secondary and supplemental. We also adopted 

rules to encourage greater investment. 

Safety is not a new mission for the Commission. Safety has been 

a principal focus of our hydropower program for decades and I’m 

committed to a strong dam safety program. But FERC also acts as 

a safety regulator when it reviews proposed liquefied natural gas 

projects, and when it oversees the construction and operation of 

those facilities. This role, frankly, is widely misunderstood. When 

FERC reviews a proposed L&G project, its primary role is as a 

safety regulator. We apply high safety standards, and we impose 

conditions, if necessary, to assure those high standards are met, 

and we reject projects that fall short. 

Congress gave us a new mission, to assure electric grid reliability. We acted promptly, adopting final rules governing the reliability program, certifying the Electric Reliability Organization, approving reliability standards that are mandatory and enforceable, 

and accepting delegation agreements to provide for regional enforcement. And, for the first time, the United States now has a 

mandatory, enforceable, reliability regime. 
10

Another new Commission mission is enforcement. One of the 

hallmarks of my Chairmanship has been the focus on enforcement. 

You gave us the enforcement authority we needed, and I want to 

thank Chairman Bingaman, in particular, for his leadership on this 

issue. We acted quickly after the enactment of the Energy Policy 

Act to exercise our enforcement authority. We adopted an enforcement policy statement, modeled on the best practices of Federal enforcement agencies, with a focus on firm, but fair, enforcement. 

This year, FERC exercised its new penalty authority for the first 

time, approving seven settlements with power and gas companies 

for various violations. We acted quickly to implement our new antimanipulation authority. We combined this new authority with an 

aggressive oversight of electricity and gas markets, and initiated a 

number of investigations into alleged market manipulation. 

If confirmed by the Senate for another term, these five missions 

will continue to be the focus of my Chairmanship. 

When I was named Chairman by President Bush, I established 

certain institutional goals. One was to improve the relationship between FERC and Congress, another was to improve our standing 

in the courts, and a third was to improve the relationship between 

FERC and the States. And, I believe we have made much progress 

in all three areas, but recognize continued improvement is needed. 

I’ve enjoyed my public service at the Federal Energy Regulatory 

Commission both as commissioner and as Chairman, and it would 

be an honor to continue that service. 

I appreciate the opportunity to testify before you today, and I’m 

happy to answer any questions you may have. I think Damien 

wants to answer questions, too, apparently. 

[Laughter.] 

Mr. KELLIHER. Sorry. 

[The prepared statement of Mr. Kelliher follows:]

PREPARED STATEMENT OF JOSEPH T. KELLIHER, NOMINEE TO BE A MEMBER OF THE

FEDERAL ENERGY REGULATORY COMMISSION

Chairman Bingaman, Senator Domenici, and distinguished members of the Committee, I am honored to be here today as a nominee to be a member of the Federal 

Energy Regulatory Commission (FERC). I would like to thank Chairman Bingaman 

for scheduling this hearing. I also express my appreciation to President Bush for 

renominating me to this post. I believe my renomination represents a vote of confidence in the entire Commission and the good work we have achieved together. 

Much of my work as FERC Chairman has been dominated by implementation of 

the Energy Policy Act of 2005. I applaud the Committee for its good work on the 

Act. This law represents the most important change in the laws FERC administers 

since the New Deal, and the largest single grant of regulatory power to the agency 

in 70 years. You gave us the tools we needed to protect the public and strengthen 

our energy infrastructure, and we are using them in a careful and disciplined manner. 

FERC has been very diligent in its implementation of the Energy Policy Act. We 

met every deadline you set for us, and beat a few. Very few of the orders and rules 

we issued during implementation of the Act were challenged in court, which I take 

as a sign that stakeholders, while not agreeing with every decision we made, believe 

we acted fairly and listened to all sides. You wrote a good law and we implemented 

it efficiently. I am proud of our work implementing the Energy Policy Act. 

Perhaps the best way to share my perspective with you is to discuss what I see 

as the Commission’s five principal missions, some of which are new, and some of 

which have changed over time. 
11

ECONOMIC REGULATION

As the courts have recognized, the primary task of the Commission is to guard 

the consumer from exploitation by noncompetitive electric and gas companies. The 

way FERC has discharged that responsibility has changed over time, however. Historically, FERC relied principally on regulation to control market power exercise. 

Over time, however, competition has played a greater role in disciplining commodity 

prices and FERC now relies on a mix of regulation and competition to protect consumers. 

I am proud of our record in the past two years of adopting reforms to strengthen 

competition and protect consumers. We adopted Order No. 890, a comprehensive reform of our open access rules, which will ensure that available grid capacity is 

measured in a fair and transparent manner and that customers have a seat at the 

table in the transmission planning process. We approved a final rule to ensure customers in organized markets have long-term transmission rights to support their investments in new resources. 

We adopted reforms to increase customer access to renewable sources of energy. 

Order No. 890 created a ‘‘conditional firm’’ service important to wind resources, and 

reformed energy imbalance charges to ensure that wind and other intermittent resources are treated fairly. More recently, we approved California’s proposal to facilitate renewable development by reforming our interconnection pricing policies. 

We continue to work to strengthen wholesale power markets. In 2006, we initiated a rulemaking to improve our market-based rate program. We also commenced 

a generic review of competition in wholesale power markets, with a goal of identifying additional reforms to ensure that these markets benefit consumers. 

We also have adopted reforms related to natural gas markets. In order to guard 

against gas price volatility, we issued a final rule to encourage greater investment 

in storage expansion. Last month we proposed a rule to increase gas market transparency. 

We remain active in all these areas because power and gas markets are highly 

dynamic. In my view, static regulatory policy is likely to fail when the markets 

themselves are dynamic and we must adapt to changes occurring in regulated industries. 

ENERGY INFRASTRUCTURE

Strengthening our energy infrastructure has been a central agency mission since 

1920. Energy infrastructure is the network of facilities that produce energy and 

transport it to where it is needed by consumers and businesses. If our energy infrastructure is inadequate, consumers are exposed to higher prices and greater price 

volatility. 

FERC has proved very efficient in its work to strengthen our energy infrastructure. Since 2000, we have approved more than 9,400 miles of new interstate natural 

gas pipelines. These pipelines contribute to domestic energy production. By improving pipeline takeaway capacity, we promoted the surge of natural gas production in 

the Rocky Mountains. We adopted reforms to encourage additional pipeline capacity, 

modifying our certificate process to eliminate unnecessary barriers to pipeline additions that raise no significant environmental issues. Pricing reform should encourage storage expansions. In the fall of 2005, we acted quickly after hurricanes 

Katrina and Rita to approve actions to facilitate greater supplies of gas during that 

winter’s heating season. 

We are also acting to strengthen the electric transmission grid. We issued final 

transmission siting rules consistent with Congressional intent in the Energy Policy 

Act, recognizing that states remain the primary siting body for transmission facilities, and that FERC authority is secondary and supplemental. We also adopted final 

rules to ensure our ratemaking policies provide adequate support for new transmission investment. 

SAFETY

Safety is not a new mission for FERC, but is one that has taken on increased importance in recent years. Safety has been a FERC mission since it established the 

dam safety program in the 1960s, and a principal focus of our hydropower program 

is assuring the safety of licensed projects. I am committed to a strong dam safety 

program. 

FERC also acts as a safety regulator when it reviews proposed liquefied natural 

gas (LNG) projects and when it oversees the construction and operation of these facilities. This role is widely misunderstood. When FERC reviews a proposed LNG 

project, its primary role is as a safety regulator. We apply high safety standards, 
12

and impose conditions if necessary to assure those high standards are met. In some 

cases, we have imposed scores of conditions to protect public safety. 

We also reject projects that fall short of our safety standards. It is important to 

understand that we do not balance safety considerations against other considerations, such as need. Doing so would compromise the integrity of our safety review. 

For example, despite the significant need for new gas supplies in New England we 

denied approval of the Keyspan project because it did not meet our strict safety 

standards. 

RELIABILITY

Congress gave us broad new authority over electric grid reliability in the Energy 

Policy Act. We exercised that authority promptly. Within 180 days of enactment, we 

adopted final rules governing the reliability program. Last summer, we approved 

the North American Electric Reliability Corporation as the Electric Reliability Organization. This March we approved national reliability standards that are mandatory 

and enforceable this summer. In April, we approved eight regional delegation agreements to provide enforcement of these standards at the regional level. For the first 

time, the U.S. now has a mandatory, enforceable reliability regime. 

In moving quickly to implement this new authority, we have been respectful of 

regional differences and the concerns of small users of the grid. We approved the 

funding of regional reliability coordinators in the West, as well as approving the 

funding of the Western Interstate Regional Advisory Board. We also modified our 

initial proposal to assure greater due process for small users. 

I am proud of our ability to undertake this new responsibility in such a timely 

and effective manner. Much work remains to be done, however. 

ENFORCEMENT

The newest FERC mission is enforcement. One of the hallmarks of my Chairmanship has been the focus on enforcement. Civil penalty is the basic tool of an enforcement agency, and by and large FERC lacked that tool before 2005. We needed enforcement authority comparable to other federal regulatory bodies to prevent market 

manipulation and market power abuse, and I urged Congress to establish an express prohibition of market manipulation, and expand our enforcement powers. You 

gave us these enforcement tools, and we are using them. I want to thank Chairman 

Bingaman in particular for his leadership on this issue. 

We acted quickly to exercise our enforcement authority. We adopted an Enforcement Policy Statement in October 2005 modeled on the best practices of federal enforcement agencies. The focus of our program is firm but fair enforcement, and we 

use our civil penalty authority to encourage compliance. The subsequent enforcement actions we have taken were all guided by the Enforcement Policy Statement. 

Earlier this year, FERC exercised its new civil penalty authority for the first time, 

approving six settlements with electricity and gas companies for a range of violations. 

We also acted quickly to implement our new anti-manipulation authority, issuing 

a proposed rule in October 2005 and a final rule in January 2006. We invoked emergency authority to make the final rule effectively immediately. We combined this 

new authority with an aggressive oversight of electricity and gas markets and initiated a number of investigations into alleged market manipulation of both power and 

gas markets. 

If confirmed by the Senate to another term, these five missions will continue to 

be focus of my chairmanship. 

When I was named Chairman by President Bush, I established certain institutional goals. One was to improve the relationship between the Commission and Congress. Development of wholesale competition policy and transmission open access 

policy was characterized by close cooperation between Congress and FERC, both 

moving towards common policy goals. I wanted to restore that relationship. We have 

made progress, but continued improvement is necessary. 

Another institutional goal was to improve our standing in the courts. FERC has 

significant authority, with new powers granted by the Energy Policy Act, but there 

are limits on our legal authority and we must respect those limits. Since I became 

Chairman, we have taken great care to assure that our decisions are rooted in the 

law and fact. We are making progress, and our solid record in the courts is a testament to that progress. 

A third institutional goal was to improve the relationship between FERC and the 

states. The U.S. has adopted a federalist system for regulating the electricity industry in this country; FERC has an important role, and state regulators have an important role. The California and Western power crisis showed that when federal and 
13

state regulators work at cross purposes, consumers suffer. If we act in good faith 

the system can work. We have made great progress, and some state regulators have 

observed that the relationship between FERC and the states is stronger now than 

it has been in ten years. 

I have enjoyed my public service at the Federal Energy Regulatory Commission, 

both as Commissioner and as Chairman. It would be an honor to continue that service. 

I appreciate the opportunity to testify before you today and am happy to answer 

any questions you may have.

The CHAIRMAN. Well, thank you. Thank you both for your excellent statements. 

I was somewhat optimistic in thinking we were going to be able 

to get all of this done prior to this vote, so we’ll just start into the 

questions, and see how many additional questions people have at 

the time the vote is called. 

Let me just start with a couple of questions that occurred to me 

here. 

One is for Chairman Kelliher—one of the issues that I know has 

been in the news a great deal is the concern about the natural gas 

supply contracts, natural gas markets in general, and concerns 

about manipulation there. As you know, I’ve contacted both your 

Commission, and the Commodity Futures Trading Commission, to 

try to make determinations in that area. I think last week the 

CTFC took the rare step of initiating legal action to get access to 

natural gas trading data from a publishing house. Is there anything you can tell us here, at this point, about what FERC is doing 

to enhance its real-time market monitoring capabilities, as they relate to the relationship between the physical commodities and the 

financial natural gas markets? 

Mr. KELLIHER. Yes, sir. I can’t comment on any pending investigations, but what I can do is approach how we’re approaching 

this kind of issue. 

The CHAIRMAN. Okay. 

Mr. KELLIHER. First of all, 6, 7 years ago the Commission did not 

have the capability to aggressively oversee either the power or the 

gas market; that’s a capability that we developed in the wake of 

the California and Western Power Crisis. And, that’s something I 

think we have made a lot of strides in. 

We do constantly monitor both power and gas markets, we also 

have established a very close working relationship with the CFTC. 

Because, legally there’s a distinction between the physical gas market and the financial gas market, but the markets don’t necessarily 

represent those legal distinctions, there’s a clear interplay between 

the fiscal, the physical, and the financial gas market. 

I think that means it’s very important for FERC and the CFTC 

to work very closely together, because you can envision manipulative schemes where there’s an attempt to manipulate financial gas 

sales, in order to affect physical gas prices, or vice versa. So, we 

have a—I think it’s fair to say, we have a closer relationship with 

CFTC now than we’ve had, certainly, in the past 5 years. We are 

working, we have a number of joint investigations with the CFTC, 

we are looking at both gas markets and power markets, and I have 

to say that currently, most of the Commission’s active investigations are gas investigations, rather than power investigations, 
14

which might not be, well, wouldn’t be obvious at all. But, we are 

very attentive to the gas markets. 

Now, our process is different than CFTC; my understanding is 

they have to go to District Court to get subpoenas issued—we do 

not have to do that. So, the fact that they’ve gone to District Court 

to request subpoenas does not mean we might not have done the 

same thing, because we don’t have to take that kind of public action. 

The CHAIRMAN. All right, well, thank you for that statement. 

Let me ask Mr. Laverty about a concern which I’ve had, and I 

think it’s a growing concern, and that is that we have seen a substantial drop-off in visitorship to our National Parks in recent 

years. I think the figures in New Mexico, our Carlsbad Caverns, 

has seen a drop of 27 percent in the number of visitors from 10 

years ago. White Sands, 28 percent down—I think this is true 

throughout the Park System. I’m not sure of the cause and effect, 

but this has happened at a time when we’ve seen substantial increases in visitor fees imposed. There’s an annual America The 

Beautiful pass which is now issued that costs $80 this year—that’s 

19 percent more than what was charged last year for the Golden 

Eagle Passport which, I guess, was comparable, an increase of 

about 40 percent over the National Park Passport, which the Park 

Service has discontinued. 

I guess I would just ask if you think there is a concern here that 

we’re to a point where in order to try to get revenue into the Park 

System, we are pricing ourselves out of the market for some Americans, and we are causing less visitors to come to the parks, in our 

effort to find revenue anyplace we can. Is this a problem that you 

think we need to think about, or address? 

Mr. LAVERTY. Mr. Chairman, thank you for that question. I’m extremely sensitive to visitation patterns in, not only the National 

Parks, but even more relative to where I’ve been with the Colorado 

State Parks. 

We did a market assessment that we commissioned with 

PricewaterhouseCoopers, and one of the things that we asked people was, why they were visiting parks, but more importantly, why 

they were not visiting State Parks. I understand that the Park 

Service is about ready to commission a study this year that will 

begin to explore that kind of a pattern. There are a number of factors that influence visitation, and not just necessarily price, although price is a factor. We know there’s an elasticity point where 

people will pay or not pay, and part of that’s determined on the 

value. 

You referenced the America The Beautiful pass—one of the 

things that is different, I think, with America The Beautiful pass 

that has been released is that it does provide you access to other 

public lands, as well as the National Parks, so in terms of a value, 

there is a perceived value that comes from that. You can, in fact, 

access other Federal lands, whereas in the past, it was just simply 

that National Park pass. 

I believe that one of the outcomes and findings of this assessment—and we need to make sure that we ask those right questions 

during this survey, is to determine, what is the influence of price 

on visitation? I know that in Colorado, gas prices now are ap-
15

proaching—they’re probably over $3 since I left, for regular. So that 

really influences choices. 

In fact, we did a study with Park visitors this last fall, when gas price was only at $2.50 to determine whether or not gas price had 

an effect on travel plans, and we found that, for a lot of people in 

Colorado, it did, in fact, affect travel choices. If you extract those 

findings and apply them across the country, there are a number of 

factors, and I think this survey will help us determine what influences visitation. 

The CHAIRMAN. All right. 

Senator Domenici. 

Senator DOMENICI. I’m not going to ask any questions. I have 

about eight or ten that I’m going to submit, and I will submit them, 

and ask that you answer them—each of you. 

I just want to say that, Mr. Kelliher, I’m very proud of your 

work. I’m very proud to have been part of your first term, and I’m 

pleased that your wife saw the goodness, greatness of your work, 

and through the goodness of her heart, let you do this again. She 

can rest assured that, after you’ve finished this term, with the excellence that you are showing, that she will not be sorry, nor will 

you. Jobs will not be short for somebody with your great capacity. 

But, for now, we’re just pleased you’ve stayed on. The Government needs you. This law we passed needs you. It’s got to be interpreted right. We hope you think it’s as good a law as we do, and 

it’s got a lot more working on to get done. 

Obviously, I don’t know you very well; you’re from my neighbor 

State. But from what it looks like, we’re lucky that you’ve decided 

to come on at this point, and you have a big job. The one that Senator Bingaman just raised is very important. 

In my State, I’d just note Carlsbad Caverns. It did not matter 

years ago, how far out it was from anywhere, so to speak, it was 

a huge attraction. It’s not now, and it’s going down, and it has 

more of what it seems that tourists wanted—it’s got great motels, 

more of them. So it’ll be good to find out, we’ll be glad to know, 

and I’m sure we’ll do what we can—I don’t know what that is. You 

have many other difficult jobs in your new one, and we wish you 

well. 

Thank you, Mr. Chairman. 

The CHAIRMAN. Thank you very much. 

I’m advised the vote has started, but why don’t we go ahead with 

questions here for a little while longer. 

Let’s see, Senator Craig would be next. 

Senator CRAIG. Well, Mr. Chairman, I’ll only make a statement, 

too; I have no questions of these gentlemen. I happen to know both 

of them personally, and think they’re highly qualified. 

Joe, let me first of all, say to you—your first term and Chairmanship of the FERC has been exemplary. I think it’s the best in recent memory, and I congratulate you for that. I’m glad you’re returning for a second round. As both the chairman and the ranking 

member have said, we need you. We need your talent, your mind, 

and your fair play, and the vigor with which you’ve approached the 

Energy Policy Act—critical to this country, critical to implementation. Your sensibility about hydro re-licensing and reform—it’s 

working, and we’re excited about that. So, keep up the good work. 
16

There’s a lot more out there to do, and we think the Senate will 

confirm you. 

I’ve had the privilege of working with Lyle in a variety of capacities; the one that is kind of unique, Mr. Chairman, and Senator 

Domenici, is the Continental Divide Trail, which moves across your 

State, across Colorado, and up the spine of the Rockies, touches 

into Idaho. We’ve gotten to know each other on trail rides, believe 

it or not, and we both know how to straddle a horse—or a mule, 

on occasion—and that’s been a very positive experience. 

Lyle brings tremendous talent—for a very unique situation. Not 

only is he going to be responsible for the National Park Centennial 

Challenge that our Secretary talks about, but he’s also going to be 

responsible for de-listing wolves and grizzly bears in my State, and 

in and around the Yellowstone eco-system. Now, if that isn’t a 

near—at least, competitive, complicated, kind of juxtapose, I don’t 

know what is—to enhance the parks, and to sustain them, and at 

the same time, make the Endangered Species Act work. Instead of 

it just being a form of preservation—an active, working, saving of 

a habitat, moving on kind of thing that we would hope, and want 

it to be. 

So, to both of you, thank you, for your willingness to serve. These 

are capacities of great responsibility. Don’t worry about your phone 

always, or you always being available by phone, Lyle; we’ll find you 

when we need you. 

Thank you, both. 

Mr. LAVERTY. Thank you. 

The CHAIRMAN. Thank you very much. 

Since this vote is going to end soon, I know Senator Wyden and 

Senator Menendez both said they had questions, and they were 

coming right back to ask those questions, so why don’t we put the 

hearing in recess for a few minutes, and then reconvene when one 

of them returns? 

Thank you. 

[Recessed.] 

Senator WYDEN [presiding]. Committee will come to order and let 

me apologize to our witnesses. It’s going to be something of a movable feast this morning because of all the votes. 

Mr. Laverty, the Inspector General released a report on March 

27 on the ethical misconduct of the former Deputy Assistant Secretary, Julie McDonald, who would have reported to you as Assistant Secretary had she not resigned last week. 

Now, the Inspector General discussed two really alarming things 

about Ms. McDonald’s conduct. No. 1, she was leaking internal documents to outside business groups who were suing the Interior Department to block environmental rulemaking. No. 2, she was bullying agency scientists, and interfering with their studies related to 

the Endangered Species Act, although she had no scientific credentials in those areas herself. 

Now, I don’t happen to believe that staff engages in that kind of 

conduct in a vacuum. I think it goes on because superiors—in one 

way or another—are looking the other way or condoning it, or perhaps even, in favor of it. So, based on that report, I announced that 

I would put a hold on your nomination until I can be assured that 

conduct of this kind at the Department of the Interior is no longer 
17

going to be tolerated. This isn’t a new concern to me. I’ve discussed 

it with Secretary Kempthorne, both publicly and privately, and discussed it at his confirmation hearing. 

Now, you asked to come see me a couple of days ago and I wanted to discuss the Inspector General’s report then, because I thought 

it was enormously important, especially given the fact that the Inspector General has said there’s an ethical quagmire at the Department. We’ve had Mr. Abramoff, we’ve had Mr. Griles, and Ms. 

McDonald. You hadn’t read the report as of a couple of days ago. 

Weren’t you a little bit curious about something like that in the Department that you would be heading, if confirmed? 

Mr. LAVERTY. Senator Wyden, I have reviewed that. 

Senator WYDEN. But the question is, why hadn’t you read it prior 

to coming to see me, knowing that there had been enormous public 

concern, that the Inspector General had issued, really an indictment of someone who would have supported you? Why hadn’t you 

at least read it prior to coming in to talk to me, if you’re so concerned about ethical practices? 

Mr. LAVERTY. Senator, I was briefed extensively on the content 

of the report. I had not read it; you’re correct. I have subsequently 

read that report. I would share with you that given the accounting 

that is reported in that report, I would be—I am concerned, I am 

concerned. And, as I shared with you in my opening remarks, all 

I can do is share with you how I would operate. 

I would not tolerate the behaviors of bullying, as reported in that 

report. And, I shared with you how I would deal with that. I believe being forthright in terms of science, holding the integrity of 

science. I would make sure that that happens. I believe that comes 

from active, proactive management. You can not sit back and allow 

those kinds of things to happen. 

I believe that you can determine what the sense and the pulse 

is as you lead an organization by listening, and listening carefully, 

to things that are going on and then take corrective action. I would 

share with you that, I would not want my name in an IG report. 

In fact, I will tell you that I will work to make sure that that does 

not happen. I think it’s important to be proactive and preventative, 

rather than allowing—for whatever reason—those things to happen 

that lead to that type of a report. 

Senator WYDEN. We’ve heard that in the past from others at the 

Department of the Interior and that’s why I’m going to ask you 

some questions to get into the specifics about how you would handle some of these situations. 

Now, the Inspector General reported that Ms. McDonald was 

leaking internal documents to outside business groups who were 

suing the Interior Department to block environmental rulemaking. 

What would you do if that was going on, on your watch? 

Mr. LAVERTY. First of all, I would make sure that folks are very, 

very clear that that doesn’t happen. I believe you have to set very 

clear performance expectations and then you manage performance. 

And, I think if there’s a breach in that performance, then you deal 

appropriately with whatever that action should be taken. To me 

it’s, again, being proactive and dealing right up front with it. Once 

you’re made aware of it, then you deal with it and that’s what I 

would do. 
18

Senator WYDEN. I’m still not clear what you would do. Would you 

bring that to the Secretary? Would you urge that that person be 

replaced? You’ve said that you would try not to have it happen, but 

what would you do? 

Mr. LAVERTY. Well, I——

Senator WYDEN. There are real questions about whether it’s even 

legal. The Inspector General report really raises the question of 

whether that even is legal. 

Mr. LAVERTY. Senator, I believe that if you’re made aware that 

those types of behaviors are, in fact, taking place, then yes you do. 

You visit with the Secretary, you visit with whoever the folks are 

that determine what is the appropriate action to take, based on 

whatever those actions are. I think you have to have very, very 

solid facts, and there’s nothing wrong with spending time to determine, you know, what is in fact the essence of that breach and 

what is the appropriate action to take. I would not hesitate at all 

to recommend to the Secretary whatever that appropriate action 

would be. 

Senator WYDEN. But she might get to stay under you if that 

went on? 

Mr. LAVERTY. I’m sorry? 

Senator WYDEN. She might get to remain in her position if you 

were the head of the Department if she engaged in that conduct? 

Mr. LAVERTY. Senator, again, I would look very closely at what 

was the breach? And then what is the appropriate action? And, if 

it’s very clear that it’s a breach of law, absolutely not. 

Senator WYDEN. The Inspector General reported that Ms. 

McDonald bullied agency scientists and interfered with their studies relating to the Endangered Species Act. She didn’t have any 

background in the area. What would you do in that kind of instance? 

Mr. LAVERTY. Senator, I would be very, very up front in terms 

of talking about expectations in terms of professional behavior. I 

tell you that I have no tolerance for that type of behavior. You can 

talk to the folks that I’ve worked with over the past of my career. 

They know that you treat people with dignity and respect. It 

doesn’t make any difference who that individual might be. 

So, I would be, if I was aware that that happened—I know that 

I can run an organization where I have a sense of the pulse of what 

the feelings are. I would deal with it right up front. 

Senator WYDEN. I want to let my colleagues ask their questions. 

I will have a number of additional questions, with respect to your 

appointment, Mr. Laverty. I am still not clear about whether you 

would allow people who engaged in the kind of conduct Ms. McDonald engaged in, to remain in those positions. So, we’re going to 

have some more to talk about. 

Senator from Wyoming, and I appreciate him waiting. I went 

over my time by several minutes and I think with Chairman 

Bingaman’s leave, you can have a couple of extra as well. 

Senator THOMAS. Very good. I had noticed that, but I didn’t say 

anything. Thank you. 

Welcome gentlemen, glad to have you both here. We had a little 

problem. I had an Indian Affairs meeting this morning, and then 

and a vote and so, try to get it all worked in. 
19

But I want to welcome you both. I think you’ve done a great job 

for what you’ve done in the past and we look forward to working 

with you in the future. 

Mr. Kelliher, legislation that we passed on FERC, gave FERC 

some additional authorities to ensure that our energy supply is reliable and affordable. One of the things that I think is—you know, 

we talk about alternatives, which is a good thing—but in the meantime we have some things we need to do. We need to get more pipelines to get our products out of Wyoming. We need to be able to 

get on with the coal-to-liquids, and so on. So some of those authorities to assist and provide incentives are there. Do you have any 

plans to help ensure that we can move forward with doing this 

rather short-term development of energy sources we know how to 

do, as we wait for the alternatives? 

Mr. KELLIHER. Yes, sir. I think we actually have done a great 

deal particularly with the Rockies and Wyoming gas production. A 

number of years ago, the price of natural gas in Wyoming was depressed because there wasn’t enough pipeline takeaway capacity. 

So in effect, you had a surplus of gas in Wyoming that couldn’t find 

its way to market. That was reducing the incentive for people to 

explore for new, more gas supplies in Wyoming. So it was completely the wrong direction, in terms of national policy. 

FERC has a very admirable record of improving the takeaway capacity from the Rockies and that’s allowed exploration and development in Wyoming and other States in the area to keep pace. Just 

last month, we approved the largest natural gas pipeline in, I 

think, 7 or 8 years, the REX-West pipeline, designed specifically to 

move gas from the Rockies and Wyoming to Midwestern markets. 

So, we’ve been doing what we can because we recognize our role, 

principally, in gas is to strengthen the infrastructure. We have the 

economic regulation role, where we police natural gas markets from 

the perspective, but we also have a duty to strengthen the gas infrastructure. 

That will allow us to maximize our domestic production. Because 

if we don’t do a good job on infrastructure, that will retard development of our domestic gas supplies. 

Senator THOMAS. And the electric infrastructure is the same. 

Mr. KELLIHER. Yes, sir. 

Senator THOMAS. I mean, if we can do mine-mouth generation 

and get it to the market, and we’re looking at the California transmission corridor, and these kinds of things. 

Mr. KELLIHER. Yes. 

Senator THOMAS. So, you think that you can be helpful in that 

area? 

Mr. KELLIHER. I think so. That’s something the West has looked 

at. A few years ago there was a study, I think under the auspices 

of Western Governors, and they looked at: what kind of power grid 

does the West need? One of the first questions you have to ask is: 

well, what kind of generation is being built? And the West looked 

at two cases. One, is relying principally on natural gas for additional electricity supplies, gas-fired generation. And the other was 

a more diverse case, using Wyoming coal, wind potential—I don’t 

think they necessarily looked at more nuclear capacity, but they 

looked at two cases. One relying on gas, one is a more——
20

Senator THOMAS. That’s all right, we have uranium too. 

Mr. KELLIHER. But the end result—the interesting thing was you 

need two very different power grids in those two cases. So part of 

it is, what is, what kind of generation are we going to build? We 

need another generation, another generation of power build, and 

what will be built? 

Senator THOMAS. Thank you. What concerns me is that, and I’ve 

been saying it, we’re for alternatives, but they’re somewhere down 

the line. We have things we can do now. We need to get incentives 

there, because the powerplants and the techniques for producing 

those are sometimes more expensive, and we need to encourage 

people to get their money in. 

Mr. Laverty, let me again thank you for your work in the West 

with the Forest Service and so on. Endangered species is an issue 

that we deal with. All of us, I think, want to continue to have endangered species, but it isn’t really working. We’ve listed about—

I don’t know—thousands of species and only recovered a few hundred. What could we do to reform ESA, in your view? 

Mr. LAVERTY. Senator Thomas, I believe that there are a number 

of things that, perhaps, can be done, and I share this from my perspective as more of a practitioner and an implementer of the ESA. 

There are a number of things that are going on, and I think examples in the Montana and Wyoming with the grizzly bear. The fact 

that we’ve been able to bring that bear to delisting by agencies 

working together, is the value of recovery. And, I think that’s the 

steps to recovery. 

Senator THOMAS. Only took 15 years. 

Mr. LAVERTY. It took us a little bit of time. I worked on the interagency grizzly bear committee 10 years ago and we were talking 

about bringing it to the point of recovery as where we could delist 

it. And, you know, it finally has arrived. 

As you look at the ESA, there are things that can be done that 

can make it more efficient. I would expect that as we look at the 

Act itself and the implementational legs, is to explore—how can we 

work to further recovery and delisting? That’s what ESA is about 

and there probably are a number of elements that can work to 

strengthen that point, to bring the focus that it is recovery. It’s not 

just listing to be listing, but it’s listing to be protecting species. 

Senator THOMAS. Exactly, thank you. 

Mr. LAVERTY. I think there are a number of elements, in terms 

of strengthening the relationship with States on how they work to 

help in that process. Being able to articulate those would be the 

step in the right direction. 

Senator THOMAS. Thank you very much, I agree with you. We 

need more science in the listing, we need to have definite delisting 

procedures, and follow them, and then get the States more involved 

as we go. Thank you very much. 

By the way, I support both of you and I hope we can move forward. 

Senator WYDEN. Senator Menendez. 

Senator MENENDEZ. Thank you. Let me welcome Chairman 

Kelliher and Mr. Laverty to the committee. The focus of my questions is with Chairman Kelliher, so Mr. Laverty, you can take a 

break for at least—I’ll let you catch your breath for Senator Wyden. 
21

[Laughter.] 

Senator MENENDEZ. Mr. Chairman, many New Jerseyans may 

not realize the role FERC has on energy that they consume, or the 

rates they pay, but the fact is that FERC’s policies and decisions 

have significant implications for New Jersey consumers. 

For instance, over the last 2 years, New Jersey was at the center 

of what would have been the largest utility merger in the Nation, 

had it gone through. Obviously, a merger of that magnitude creates 

a number of questions for consumers, regulators, and the States. 

As one of the Federal regulators that has to approve the merger, 

FERC sign-off is an integral part of the process, and its response 

also signals how serious it takes the issues being raised by all the 

parties involved. 

When FERC gave this particular merger the green light, rather 

quickly, and without a hearing process, I think it surprised many 

New Jerseyans, to say the least. Especially when our State Board 

of Public Utilities had a long list of questions they were trying to 

get answered. I think the message New Jerseyans got, was that 

FERC wasn’t looking out for their interest to the extent that they 

would expect. 

I would hope that isn’t the message you are trying to send. So, 

I raise the merger process simply as a very visible example for New 

Jersey, of the role FERC has for issues impacting our State, and 

for that fact, any other State. Frankly, FERC’s response to the 

merger, coupled with current issues that had regulators in our 

States worried, have resulted in what I can describe as a lack of 

confidence in FERC’s commitment to carry out its role of Federal 

oversight. It’s in that context that I want to ask you a couple of 

pressing questions on issues for our State. 

Last December, FERC approved PJM’s reliability pricing model 

with the intention of encouraging new powerplants in New Jersey 

and other areas where they are needed the most. However, there’s 

a severe concern that this pricing model would have the effect of 

transferring hundreds of millions of dollars from New Jersey electricity customers to powerplant owners, and could potentially cost 

New Jersey customers more than $1 billion a year. There also 

seems to be no assurances that these payments will actually result 

in the construction of more powerplants. Can you say for certain 

that the RPM will result in new powerplant construction and will 

not take dollars away from customers? 

Second, in fact, PJM projects that its transmission expansion will 

reduce revenues to New Jersey powerplants, countering any incentive to build new plants that RPM could offer. How does FERC contend to address that contradiction? 

Mr. KELLIHER. Can I address the initial question about the 

Exelon merger? 

Senator MENENDEZ. I really didn’t have a question, it was a 

statement for context and since my time is limited I’d appreciate 

an answer to these. 

Mr. KELLIHER. I’d like to answer that in writing if I may. 

Senator MENENDEZ. Absolutely. I’m going to have plenty that 

you’ll have to. 

Mr. KELLIHER. With respect to RPM, the problem that we’re addressing is that we were not seeing continued entry by new genera-
22

tion, not just in New Jersey, but in the Eastern PJM region. And 

so, we were looking at very imminent reliability violations, perhaps 

being worse in Northern New Jersey than anywhere else in the 

Mid-Atlantic region. So, we were not seeing that kind of entry, we 

were looking at what kind of actions could FERC take to encourage 

entry—new entry, new generation. 

So, we looked at—there’s different models. One is a long-term 

contract, another model is a capacity market. But a capacity market, if it’s going to encourage new entry, it has to be forward, it 

has to look out a couple of years. We’ve seen short-term capacity 

market proposals and the Commission I think, I personally favor 

the long—the forward capacity market, because it allows new generation to compete. Rather than simply rewarding existing generation, it will encourage entry by new generation. I think PJM has 

had its first auction under RPM and I thought the initial results 

were very encouraging. I can elaborate in writing, but I thought 

the initial results in the first——

Senator MENENDEZ. But the question is, how do—can you say for 

certain that the RPM will result in new powerplant construction 

and not take away dollars from customers? If in fact, it’s transmission plans, expansion plans reduces revenues to New Jersey 

powerplants, it counters any incentives to build those plants, but 

at the same time it takes away dollars from New Jersey customers. 

How do you reconcile that contradiction? 

Mr. KELLIHER. There is a reliability problem in Northern New 

Jersey. There’s more than one way to solve that problem; one is 

entry of new generation, one is transmission, and also a combination of the two. In New Jersey, they very much support at least 

being, having transmission be part of the solution. I think the view 

in New Jersey—and we’ve had New Jersey Commissioners, Fred 

Butler and others, participate in our RPM proceedings—and 

they’ve argued that a generation-only solution probably isn’t going 

to work. It has to be a combination of new generation and new 

transmission and that’s really the approach that we’re taking. 

We know that the status quo is failing now. The status quo 

wasn’t working. We were looking at imminent reliability problems 

in New Jersey. We had to take some action, and our record did 

support the conclusion that a forward-capacity market will result 

in entry of generation rather than rewarding existing generators——

Senator MENENDEZ. I understand that there is a necessity to 

take action. The question is that the action taken must, in my 

mind, provide some degree of safeguard that we just don’t have a 

transference of money without the results. 

Mr. KELLIHER. I agree. 

Senator MENENDEZ. And, I don’t see where your safeguards are 

in that regard. 

Now, Mr. Chairman, I have several other questions, but I’ll wait 

for a—I assume we’re going to have a second round. 

Senator WYDEN. We will. 

Senator Tester. 

Senator TESTER. Thank you, Senator Wyden. 
23

I also want to thank Mr. Kelliher and Mr. Laverty for being here 

today. I also want to thank you for stopping in my office and visiting with me during the last week. I really appreciate that. 

My first volley of questions will be for Mr. Kelliher. These are 

going to be pretty short, the questions, so hopefully we can get 

through a bunch of them. 

In your opinion, as Chairman of the FERC, is deregulation good? 

Mr. KELLIHER. First of all, I don’t think Federal policy is deregulation. Federal policy has never been deregulation, it’s not FERC 

policy now, it hasn’t been FERC policy in the past. Deregulation to 

me—perhaps I’m too literal, it means the absence of regulation and 

we have never had an absence of regulation in wholesale markets. 

Now, perhaps State regulation in some respects has been deregulation, but that’s not been Federal policy. Federal policy, since 1978, 

has been promoting competition in wholesale markets, relying on 

both regulation and competition. Now there’s another market, 

though, and that’s the retail market and States have taken different approaches to that. 

I think competition’s the right policy at the national level. Congress reaffirmed it in 2005, but I think you can draw different conclusions on whether deregulation has been a success at the retail 

level. 

Senator TESTER. Does deregulation encourage competition? 

Mr. KELLIHER. In retail markets, I think it depends on how you 

do it. 

Senator TESTER. Wholesale. 

Mr. KELLIHER. I don’t really think our Federal policy is deregulation. I think it’s, it is competition, but it’s also regulation. We, what 

we are using——

Senator TESTER. I hope this isn’t an unfair question, but I was 

just wondering if deregulation encouraged competition? 

Mr. KELLIHER. Does deregulation—well, our policy is competition. We have used regulatory authority to promote competition. I 

don’t think it’s an either/or proposition of regulation or competition. 

We rely on both. 

Senator TESTER. Okay. You’re very familiar with this. In 1997, 

the Montana Legislature chose to deregulate with a lot of the policies that were passed by both parties—it’s not a single party—that 

were passed in Congress previously 4 years before that. I would interpret that as policies coming out of this body to FERC to encourage deregulation. You don’t interpret it that way? 

Mr. KELLIHER. No, I think FERC—States have taken different 

approaches toward retail competition or retail deregulation. I think 

FERC’s focus has been narrowly on wholesale markets. 

Senator TESTER. Okay. 

Mr. KELLIHER. And——

Senator TESTER. If competition doesn’t exist in a certain region, 

what’s FERC’s responsibility? 

Mr. KELLIHER. Well, we—our general policy with respect to market-based rates is, we view market-based rates are not a right for 

a seller, for a generator. It’s a privilege. To get that privilege, they 

have to make certain demonstrations. They have to prove to the 

Commission’s satisfaction that they don’t have market power or if 

they have it, that they’ve mitigated market power. 
24

Senator TESTER. Is there competition in Montana, wholesale? 

Mr. KELLIHER. That bears on a pending matter at the Commission. PPL Montana has asked—has requested market-based rates. 

We approved an order, I think in September of last year that 

granted market-based rate authority. Montana has sought rehearing, and we are giving very serious considerations to the view of 

the State. 

Senator TESTER. Yes, the ruling came down on May 18, 2006 and 

FERC ruled that PPL Montana, you know, that there is competition so that there’s no need for cost-base. In October, the end of October—Montana PSC and the MT Consumer Counsel requested a 

rehearing, and they have yet to hear back. What kind of timeframe 

are we looking at for that? 

Mr. KELLIHER. I promise I will take another look at the order. 

We—right now I do not believe there’s a, it has been scheduled. 

Part of the argument in that order is what’s the geographic market? Because when we’re looking at market power, that’s one of the 

issues. I think the Montana argument is the geographic market is 

smaller that what FERC concluded in its——

Senator TESTER. And the other issue deals with competition in 

the wholesale market. You know, the PPL owns the water generation, the hydro generation, and they can sell it very cheap, if they 

choose to. It’s a lot like renewable energy, if the petroleum companies want to drop the prices, they can blow renewable out of the 

water. 

So, the question is for us, for me, for the PSC, for the Consumer 

Council, for Democrats, Republicans, it’s a consensus issue—how 

could FERC make a decision that there’s competition in Montana, 

when there isn’t? 

Mr. KELLIHER. The key—the initial question is, what’s the geographic market? And, the market that we defined, in our initial 

order, suggested that PPL Montana had a market share that 

ranged from 13 percent to a high of 24 percent, and our——

Senator TESTER. Okay. 

Mr. KELLIHER [continuing]. So in certain, and in——

Senator TESTER. All right. The power rates have doubled in Montana over the last 10 years. I do appreciate the fact you said you’re 

going to take a look at that, and get a decision back; I think it’s 

important for the people of the State of Montana. 

I would also point out that, if taxes in Montana would have gone 

up the last 10 years, like power rates have gone up in Montana 

over the last 10 years, there would be a revolution in that State. 

There would be a revolution everywhere, if that was the case. It 

is a critically important issue for the State of Montana. My perspective is we gave away one of the biggest assets we had when—

and I told you this the other day—when the legislature, in 1997, 

decided to deregulate—it has been an abysmal failure. 

I think, quite frankly, there’s been policy that’s come from the 

Federal level, and FERC, and I’m not pointing fingers at any political party, but the fact is that this has not worked, as advertised, 

at all. So, I think it puts it on your back. 

You may have—from a Montana perspective—the most powerful 

agency in the Federal Government right now. So, it’s important 
25

that you take a hard look at this. Once again, I appreciate it, I’ll 

come back to Mr. Laverty next round. 

Thank you very much. 

Senator WYDEN. Senator Burr. 

Senator BURR. Thank you, Mr. Chairman. 

Let me welcome both of our nominees, and say to my colleagues, 

I’ve had the opportunity to work with, or to visit with both nominees extensively. Certainly, Chairman Kelliher was on the Energy 

and Commerce Staff on the House side. I think the incredible thing 

about these nominations is that we have a tremendous amount of 

information as members to evaluate your backgrounds, your capabilities and in Joe’s case, to look at how you’ve led the FERC. 

I don’t think I speak as a single member, that I am delighted to 

have nominees that have as strong of an experience, and what I 

think has been leadership in Chairman Kelliher, at a very difficult 

time. I empathize with Senator Tester in Montana, because every 

State has those challenging issues. 

The one thing that I can say to my colleagues is that I’ve never 

found a situation where Chairman Kelliher wasn’t: No. 1, responsive; No. 2, knowledgeable of the issues; and, No. 3, decisive from 

the standpoint of what the power of FERC was. There are times 

I wish myself that FERC had some retail jurisdiction, and the realities are, you don’t. When I come to my senses, I realize, I don’t 

want you to. That, to eliminate that would eliminate the opportunity for competition. 

Mr. Laverty I’ve had the opportunity to meet just in the last several weeks, and I am always one that’s critical, if in fact, a nominee 

comes up that doesn’t have the credentials to fill the slot that he’s 

being asked to fill. 

This is one part that I can highlight the administration on, the 

fact that I think they found somebody that had more than enough 

to fill the credentials of what the job suggests—Director of Colorado State Parks, Associate Deputy Chief of the U.S. Forest Service, Regional Forester, Rocky Mountain Region, Director of Recreational Wilderness Resources—when we talk about somebody in 

Fish and Wildlife, we look for somebody that understands these national treasures that we have, this bond, this commitment that the 

United States makes with the people of the country on exactly 

what we’re going to protect. Clearly, as society changes, so does the 

implementation of how we do it. Because if you’re in Montana, the 

access that you want for snowmobiles is different than if you’re in 

North Carolina, where we would be, probably locked up if we had 

a snowmobile. 

I think it’s difficult to find somebody that brings, not just the 

varied background of areas that they’ve been involved in, but the 

regional experiences that you’ve had, at both a Federal and a State 

level. I think that brings a unique opportunity to us at Fish and 

Wildlife. 

Let me just say that in the conversations that I have had with 

both nominees, I have found both to be incredibly straightforward, 

incredibly genuine in the answers to my questions, and last, unbelievably knowledgeable about the task that they’ve been asked to 

do. 
26

I think it’s safe to say, as a member that’s been 17 years in business, I have to sometimes wonder why someone would take a nomination with just a year and a half left in an administration, and 

the only answer I can come up with is that it’s somebody that’s 

very confident that their background brings a lot to the job they’re 

asked to do, because of the limited amount of time they have to 

perform that. Because, as we know, like every Congress changes, 

we’re apt to change the rules, with every administration, they’re almost certain to change the personalities. 

So, I say to my colleagues, this is a proud day that we’ve got two 

incredible nominees in front of the committee. It’s my hope that we 

will be expeditious, that members that still have problems will air 

those problems, either publicly today, or privately thereafter, and 

conclude them, and let us move forward. I think the only way that 

we fall short of our responsibility, outside of putting incompetent 

people in, is not to put anybody in. 

It’s my belief that we have crucial decisions to make within the 

Interior, with Fish and Wildlife. Absolutely we have crucial decisions to make at FERC as their hearings proceed, almost daily. It 

really is the framework of what the future for our generation of 

electricity and for the growth of our economy is. 

So, I for one, thank both of these nominees for their willingness 

to serve. I yield back, Mr. Chairman. 

Senator WYDEN. I thank the Senator from North Carolina. 

Let me go now to some of the work that you did in the State of 

Colorado, Mr. Laverty: this is after you had served at the Federal 

level, you were director of the Colorado Division of Parks and Outdoor Recreation for 5 years. 

Now, Greater Outdoors Colorado provides State lottery money for the State Parks, and they withheld $8.5 million earlier this year 

from your Agency, because you couldn’t account for past spending, 

and didn’t seem to have financial controls in place. Now, my staff 

called, tried to verify this information, but they were told by the 

organization, that you were asked to provide a current business 

plan, it took awhile, and then you gave them one, but it was from 

2002. 

Now, Greater Outdoors Colorado finally did agree to release the 

money to your Department, but that came only after the State 

auditor agreed to conduct what the auditor calls, a ‘‘full blown 

audit’’ of the Division of Parks, and that is expected to begin shortly. 

Is any of what I’ve said factually inaccurate? 

Mr. LAVERTY. Senator, if I could respond——

Senator WYDEN. Just yes or no—is any of that factually inaccurate? 

Mr. LAVERTY. A portion, yes. 

Senator WYDEN. Please, then, let us hear your response to it. 

Mr. LAVERTY. Thank you. 

You are correct that GOCO—Great Outdoors Colorado—asked for 

some financial information on invoices that we had paid. Those invoices have been paid by the State of Colorado to contractors for 

work that was done on State Parks. Those invoices were approved 

by the Department of Natural Resources Controller. All of those invoices were, in fact, correct. 
27

GOCO, pending an audit, asked for some additional information, 

and that additional information was the part that did not exist in 

the format that GOCO asked for. So, we pulled that information together, and—as I would expect that you also are aware—that we 

provided that information to GOCO. That information took some 

time to put together. That was the part that we worked on with 

GOCO. That has been satisfactorily resolved. 

Now, the part about the State audit—my recommendation to the 

Executive Director of the Department of Natural Resources was, 

given the concerns that were being expressed by the Great Outdoors Colorado folks, is that we wanted to be sure that the structure was in place to be absolutely accountable, that we had the internal controls. The State Auditor periodically reviews State organizations, so we asked for—we, State Parks, and the Department 

of Natural Resources—asked for the State Auditor to come and do 

a performance review, and that process is underway right now. 

The business plan you referred to was for Cheyenne Mountain, 

and perhaps you have some additional information on that. We developed that business plan based on changing dynamics of what’s 

going on in Colorado. When we started the development of Cheyenne Mountain, Cheyenne Mountain was a Park that was originally planned with, to be developed with GOCO funds. The legislature changed and continued to change the funding mechanisms for 

Colorado State Parks. The legislature instructed us to develop a 

Park operation that would be fully sustainable. 

The original plan for Cheyenne Mountain was based on a 

premise that there would be additional State funds supporting that 

operation. Those funds changed. The rules of engagement changed 

for us, so we undertook a revised business plan. We just had the 

Governor’s office review that business plan, and that is to be released with GOCO here, shortly. 

Senator WYDEN. Well, we’re going to have some additional questions. The bottom line is that the figure is $39.8 million—a 363 

percent increase, according to the January 30 draft of the plan. 

But, we’ll have some further conversations with you about it. 

Now, the Denver Post reported that you used State money to buy 

a horse for you to ride, and which you later had your Department 

sell to your son-in-law. Now, my staff followed up on this, and the 

Colorado Department of Natural Resources official who oversaw 

the Agency’s budget confirmed that this was done against the advice of the Department of Natural Resources, and that the money 

was used to buy the horse, and you would be in some private, you 

know, trail ride, and then the legislative panel ordered you to sell 

the horse, and you sold it not in a public kind of way, at a public 

auction, but to your son-in-law. 

Now, again, any one of these things, I think, wouldn’t cause me 

to ask all of these questions. But, it is the pattern, Mr. Laverty, 

it is the fact, you’re going into an agency after Mr. Abramoff, Mr. 

Griles, Julie McDonald—I’ve got quite a bit more of this. 

We went and talked to somebody, I’m sure you know well, the 

former Comptroller of the Colorado Department of Natural Resources. He’s the fellow who oversaw your agencies. He was quoted 

in one of the papers as saying, ‘‘God help us if he takes over our 

National Parks.’’ I’ve got plenty of critics, too, so we all hear that. 
28

But then we called him up, to verify whether that was his opinion, 

and he said, you were unethical. 

So, I just feel we’ve got to get to the bottom of all of this, and 

tell me about the horse, and we’ll try to do some other of this in 

writing, but I think any one of these actions wouldn’t be the kind 

of thing that would be a showstopper for me. But, it is the pattern, 

it is the fact that when we had our first conversation, after all of 

this concern about the disgraceful conduct of Julie McDonald, you 

hadn’t read it, and I’ve got a lot of remaining questions. 

So, tell me about the horse, and let’s see if we can get your response on that. 

Mr. LAVERTY. Certainly, thank you, Senator. 

We did purchase a horse, the State of Colorado, purchased a 

horse——

Senator WYDEN. With State money? 

Mr. LAVERTY. Correct, yes. 

Senator WYDEN. Okay. 

Mr. LAVERTY. With State Park funds. 

Senator WYDEN. For you. 

Mr. LAVERTY. No, no, sir. 

Senator WYDEN. Oh. Who was the horse for? So, all of these papers are inaccurate, I guess. 

Mr. LAVERTY. Well, I would tell you that the purpose of which 

that horse was purchased was to establish an equestrian unit in 

our urban parks, we have three urban parks. If you look at urban 

parks around the country, equestrian units are a very, very effective way, not only to maintain an officer presence in the park, but 

also in terms of visitor contact. That was the purpose of which that 

horse was acquired. 

You are correct, that there was a question that came up during 

the legislature conversations with one of the members. In my conversations with the Executive Director, we decided we were not 

going to put anything in jeopardy in terms of funding for the Department or the Agency, and we sold the horse. 

Senator WYDEN. I’m looking at the clippings, you say it’s certainly an appropriate use if the Agency had a horse, and that was 

an opportunity to interact with folks who had an interest in what 

our business is all about, there’s nothing wrong with that. That’s 

what you said, and it comes after the Department said, ‘‘Don’t do 

it.’’

Did you sell it to your son-in-law? 

Mr. LAVERTY. Yes, sir, I did. In fact, we made the decision that, 

after the conversation in the Department that it was appropriate 

to sell the horse, we said, ‘‘Let’s sell the horse,’’ so we sold the 

horse. I had a conversation, we were talking about the need to sell 

the horse, and my son-in-law said, ‘‘I’d be happy to buy it.’’ I said, 

‘‘Great.’’ So, we just sold it for the price at which the State acquired 

the horse. 

Senator WYDEN. I may have some additional questions, I know 

colleagues have been waiting. 

Senator from New Jersey. 

Senator MENENDEZ. Thank you, Mr. Chairman. 

Chairman Kelliher, let me ask you: recent testimony before the 

FERC, by Dr. Joseph Bohring, who’s the market monitor for PJM, 
29

called into serious question the ability of the PJM marketing, monitoring unit to adequately, and impartially, monitor electricity markets, and therefore protect New Jersey consumers from market 

power abuses. 

Rather than launch a FERC-initiated investigation—certainly 

appropriate for this regulatory agency—FERC has, instead, deferred to the PJM management for an internal investigation. This, 

despite the fact that Dr. Bohring’s testimony illustrates that the 

PJM management is the one thwarting his unit’s ability to do its 

job. A little bit to me like having the fox guard the chicken coop. 

If the State of New Jersey is not satisfied by this internal review 

by PJM, will you commit to opening a FERC investigation into this 

matter? 

Mr. KELLIHER. We currently have two complaints pending, one of 

which New Jersey is a, the New Jersey Board of Public Utilities 

is a party to, that addressed these very same questions—some 

urged the Commission to shut down the independent investigation 

that PJM has commissioned, and initiate its own investigation. 

We are—we are now obliged to follow the ex parte rules, we have 

to give all parties due process. We’re receiving comments on these 

two complaints. I really can’t address——

Senator MENENDEZ. So, you can’t make a commitment to that. 

Do you think that in the first place, deferring to an internal review, 

versus having your own, when the testimony is such that it says 

that, that unit is, in essence, thwarting the ability of the market 

monitor to do its job was the right decision in the first place? 

Mr. KELLIHER. That is exactly one of the questions posed by the 

complaints, that FERC should conduct its own investigation, so I 

can’t answer that question, because——

Senator MENENDEZ. All right, let’s see if we can get it to a question you can answer. 

As I understand it, the market monitor is, essentially, the street 

cop to ensure that there is not a usurpation of market power. 

Would you agree with that assessment? 

Mr. KELLIHER. No, I would not, actually. 

Senator MENENDEZ. Okay, well, let me give you my concern, and 

then maybe I can get your response. 

My concern is that the independence and enforcement power of 

the market monitor is undermined, it would, in essence, be the 

equivalent of taking the cop off the street. 

Mr. KELLIHER. The PJM market monitor, by his own statements, 

does not have enforcement power. This is a question that addresses 

the legal authority of Federal agencies to delegate authority—particularly enforcement authority—so the PJM market monitor has 

said he has no enforcement authority, and to my knowledge, he’s 

not requested enforcement authority. 

Senator MENENDEZ. I’m not talking about enforcement authority, 

I’m just talking about the ability to produce information for those 

who have the enforcement authority to do so. 

Mr. KELLIHER. But, I just want to clarify, you described him as 

a cop on the street. 

Senator MENENDEZ. Yes. 

Mr. KELLIHER. And if he doesn’t carry a gun, and can’t carry a 

gun——
30

Senator MENENDEZ. Yeah, but he makes a police report. 

Mr. KELLIHER. We view him as someone, he’s more—to use the 

same kind of analogy, he’s the neighborhood watch. 

Senator MENENDEZ. All right, let me ask you about this: do you 

agree that the impartiality and independence of the market monitors is key to protecting the taxpayers? The ratepayers, I should 

say? 

Mr. KELLIHER. It is important that the market monitor have sufficient independence to do their job. But, it’s the Commission’s responsibility to protect the public, and prevent market power abuse, 

prevent manipulation. 

Senator MENENDEZ. Which, given the substantial concern expressed by the PJM State Utility Commissions over the issues of 

independence for the PJM market monitor, would you welcome 

their recommendation to consider making the PJM market monitor 

unit accountable to a joint FERC-State Utility Commission Board? 

Mr. KELLIHER. That is another issue that is raised in the complaints that I’m not able to address. 

Senator MENENDEZ. Is it your view that FERC is ultimately responsible for ensuring just and reasonable rate occurrences within 

the markets operated by the RTLs? 

Mr. KELLIHER. Without question. 

Senator MENENDEZ. Well, let me ask you: it seems to me that 

one of the most-discussed topics for Federal legislation is regarding 

limiting powerplant emissions of carbon dioxide and other greenhouse gases. The stringency of future regulation of these pollutants, the flexibility available for compliance, the availability, cost 

and cost-effectiveness of installing technology to control these pollutants are variables that can have major impacts on the supply 

and cost of coal-fired electricity. 

Yes, the FERC has encouraged policy designed to bring such 

coal-fired electricity into New Jersey, and other Eastern PJM 

States through large transmission lines. This approach wagers billions of dollars in transmission investments on the supply of electricity that is likely to become more expensive and less certain. 

When and how will FERC incorporate the prospect of greenhouse 

gas emission regulations into its policies? 

Mr. KELLIHER. I’d say we’re already doing that. We do not have 

direct responsibility in this area, we are not an emissions agency, 

but we’re taking a number of actions that are fully consistent with 

controlling greenhouse gas emissions. Just last month, we approved an order—a California order—to promote the development 

of wind, geothermal, solar, hydro generation. 

FERCs, historically, have not tried to choose the primary fuel for 

electricity generation in the United States. We generally think 

fuels—at least, I personally think, fuel diversity is a good approach—we shouldn’t bet entirely on one fuel. In recent years, 

we’ve bet entirely on natural gas. I think we’re trying to pursue 

more fuel diversity in the way this country generates electricity, 

and we are changing our policies to encourage renewable energy 

development, we’re also taking a more aggressive approach on demand response. 

We’ve had two conferences in the past month, looking at: how do 

we improve demand response in this country? That is entirely con-
31

sistent with global climate change approach. Because, if we can develop more effective demand response, less generation will be build. 

Senator MENENDEZ. Well, since you have encouraged policies designed to bring coal-fired electricity into New Jersey, and other 

Eastern PJM States through large transmission lines, it seems to 

me that you have the power to encourage other policies that don’t 

wager as strongly as it seems to me you’ve—I know we have Atlantic City in New Jersey, but you know, we’d prefer, on this issue, 

not to wager and put our bets largely in one energy source. It just 

seems to me that the way the Commission is pursuing it is doing 

it in such a way that it has made an enormously large wager in 

an area in which there’s enormous subject here, of debate in the 

Congress, about moving in a different direction. 

So, you know, I have a—I have a problem with that. I have other 

questions; I will submit them for the record. 

I have to be honest with you—I’m not satisfied by the answers 

I’ve received to the previous two. They create serious concerns for 

me about where we’re headed, and I will also be looking forward 

to your comments you said you’d submit to us about the—although 

it wasn’t a question—I’d like to hear what you had to say about 

the merger, which would have been an enormous challenge to the 

State, without having all of its questions resolved. 

I mean, we look to you as one of the major oversight entities. 

When we get the sense that that oversight isn’t there, when we default to independent reviews of what, in essence, we believe FERC 

should be doing, we say to ourselves, ‘‘We’re not quite sure that the 

consumer is being protected here in a way that it should.’’ So, I 

hope you’re going to be able, in your answers, to convince me differently, but right now, I’m not convinced. 

Senator WYDEN. Well, what we’ll do now—Senator Tester will go 

next, and Senator Burr after that. I will have some additional 

questions. Senator Tester will chair for the next few minutes, and 

we, again, thank the witnesses for their patience with all of this. 

Senator TESTER [presiding]. Thank you, Senator Wyden. 

Mr. Laverty, the point that Senator Wyden brought up here a 

minute ago was not something I was going to ask about, but I’ve 

got to ask about it. Because it just doesn’t, quite frankly, smell 

right to me at this point in time, setting on this panel, and it deals 

with the horse. Is there any rules or guidelines for advertising and 

bidding, and did you follow those? 

Mr. LAVERTY. Senator, we talked to Department contracting people to say, ‘‘Is this okay?’’—the objective was to sell the horse as 

quickly as we could. We talked to the contracting and procurement 

folks, and they said, ‘‘No, there’s absolutely no problems.’’ Everything was, in fact, consistent with the Department rules and regulations. 

Senator TESTER. How long did the Department own the horse? 

Mr. LAVERTY. It was just about 6 months. We had purchased it, 

and we were going to begin to implement the equestrian unit the 

next season. 

Senator TESTER. One horse does constitute an equestrian unit? 

Mr. LAVERTY. Yes, sir. 

Senator TESTER. Were you going to have multiple riders? 

Mr. LAVERTY. Yes. 
32

Senator TESTER. Sixteen-hour days for the horse? 

Mr. LAVERTY. No, sir. The intent was to bring the equestrian 

units in our urban parks, which is Chatfield and Cherry Creek 

State Parks. These are essentially Denver Metro Area Parks. The 

objective was to bring that equestrian unit on the park to make 

visitor contacts and doing enforcement work in those Parks. That 

was the intent to do that. It’s a very, very effective tool. 

Senator TESTER. Yes, I agree, it can be incredibly effective. I 

hope you realize from my perspective, that it doesn’t look very good 

when you’ve got a State horse, and it gets sold to a relative, fairly 

close relative, you know, I mean, vertically integrated relative, with 

no bidding, no advertising—it just, I just hope you realize it just 

isn’t quite what I would thought. 

I’ll go back onto my questions now. The environment, the Endangered Species Act. Removal of animals—which is all something, we 

always appreciate, because that means there’s success in the 

field—how much effort is, when an animal is projected to be removed, or is in fact, removed—how much effort is put into determining the impact, so that they’re not re-listed a short period later? 

Mr. LAVERTY. Senator, the example would be the grizzly bear, 

perhaps, in Montana and in Idaho and Wyoming. The States have 

put together rigorous monitoring plans to make sure that those 

populations are, in fact, sustainable, and would be involved in the 

monitoring of those plans. So, I think it’s that cooperation between 

the States and the agencies working together to make sure that 

that’s it. I think it’s a very rigorous model. 

Senator TESTER. So there is a fair amount of research, input, scientific method, as the Senator from Wyoming talked about, to determine when we take these animals off, that they’re going to remain off for the foreseen future? 

Mr. LAVERTY. Yes, sir. That really becomes a very science-based 

decision. 

Senator TESTER. The agencies that are involved in that are, not 

only you, but State agencies, Park Service—who else? 

Mr. LAVERTY. It would be the Division of Wildlife in those States, 

working with the land managing agencies, the Forest Service, the 

Park Service, Fish and Wildlife Service. 

Senator TESTER. Okay. 

Mr. LAVERTY. All of those agencies working together, I think, 

bringing together that knowledge base to support the decision 

to——

Senator TESTER. It’s a collaborative effort. 

Mr. LAVERTY. Yes, sir. 

Senator TESTER. Good, thank you. 

I talked with you when you were in my office—whenever it was, 

earlier this week—about the bison range. I’ve talked to other members in the Department of Interior about that, too. Since you are 

up for confirmation as Assistant Secretary of the Fish, Wildlife and 

Parks—the question I have, and—are you in that position now, by 

the way? 

Mr. LAVERTY. No, sir. 

Senator TESTER. So, is it a fair question to ask you, if they’ve 

been at the table yet to talk about the bison range? Because the 

Fish, Wildlife and Parks are a critical component as—have they 
33

been at the table to talk about future management? When was the 

last time they were at the table, and how can you, as Administrator, make sure that we get everybody at the table and do the 

same kind of collaborative effort here, as you talked about with the 

Endangered Species Act? 

Mr. LAVERTY. Senator, I understand—and I can’t recall the exact 

date—but it was earlier this spring that agencies, folks from the 

Fish and Wildlife Service, and the Assistant Secretary’s Office, actually went to Montana and met with the tribes, and they’ve talked 

about the Annual Funding Agreement for this next—continuing 

this next year. Those discussions have, in fact, taken place. 

Senator TESTER. Are the folks in your Agency in D.C. intimately 

involved in these negotiations, or is it pretty much left to the Region? 

Mr. LAVERTY. Senator, I believe that the folks in the Washington 

office are actually at the table. They were there for those discussions and conversations. 

Senator TESTER. Okay. 

Senator Burr, did you have any questions? 

Senator BURR. I do, I thank you, Mr. Chairman. 

I will take the opportunity to beat that proverbial dead horse 

again. 

[Laughter.] 

Senator BURR. Mr. Laverty, did the State sell the horse for less 

money than it paid for the horse? 

Mr. LAVERTY. No, sir. 

Senator BURR. Well, I would say this is a good day, because usually I find the Government pays way too much, so I’m refreshed to 

find out that the State of Colorado did not lose money. 

I take for granted that the purchase of the horse was to begin 

a pilot program to see if this equestrian program was something 

that, in fact, you would roll out with more than one horse? 

Mr. LAVERTY. Absolutely, Senator. And, you know, based on conversations that I’ve had with other enforcement agencies around 

the country and in——

Senator BURR. I think we buy into it. The Capitol Police have a 

very big equestrian program here and it’s very, very successful just 

simply because of the crowd control and the grounds here. 

Let me ask you some very candid questions if I can——

Mr. LAVERTY. Please. 

Senator BURR [continuing]. And maybe it will cut through some 

of the things that we’ve heard today. Are you an ethical person? 

Mr. LAVERTY. Am I an ethical person? 

Senator BURR. Yes, sir. 

Mr. LAVERTY. Absolutely. 

Senator BURR. Have your ethics been questioned by the State of 

Colorado? 

Mr. LAVERTY. No, sir. 

Senator BURR. Were your ethics ever questioned by the U.S. Forestry Service? 

Mr. LAVERTY. No, sir. 

Senator BURR. Did the State of Colorado ever raise any ethics 

questions as it related to all of these things that Senator Wyden 

has said were in the press? 
34

Mr. LAVERTY. Not at all. 

Senator BURR. When you served as Director of Recreation and 

Wilderness Resources for the U.S. Forestry Service, you were in 

charge of developing an agency budget, and field coordination of 

that budget, of over $300 million. Did they ever question how you 

constructed your budget or how the field coordination of that 

money was implemented? 

Mr. LAVERTY. No, sir. 

And if I just could just add: I’d mentioned before you came in 

that I was asked to lead the implementation of the National Fire 

Plan. That was a Fire Plan that was funded by this Congress that 

was approaching, between the Department of the Interior and the 

U.S. Forest Service, approximately $2 billion. And I’m a strong believer of performance accountability. You establish very clear performance measurement systems. We reported back on how those 

funds have been invested. So, I really believe that in terms of, you 

know, who I am, performance measurement is extremely important. 

Senator BURR. Well, I appreciate that because I think you’ve 

been challenged with greater budgets that had a much greater impact from standpoint of area and the implications of the implementation of that budget, and you have passed it with flying colors, 

based upon what I’ve looked at your background. 

Now, you have—or continue to serve—on a number of boards. 

You have—or are serving on—the Board of Directors of the National Association of State Park Directors, Board of Directors, National Society of Parks Resources, Board of Directors of the Colorado Fourteeners Initiative, Board of Directors Volunteer for Outdoor Colorado. You are an Advisory Board member for the Salvation Army. Do any of these boards allow people that have questionable ethics to serve as a board member? 

Mr. LAVERTY. No, sir. 

Senator BURR. I would only point out to my colleagues that we’re 

all the subject of newspaper articles. It’s the nature of the job we 

do. For the most part, I’ve found we don’t read the bad ones about 

ourselves, we only read the bad ones on others. Maybe we need to 

start mandating that we read the bad ones on ourselves to find out 

that we’re all susceptible to being painted as somebody that we’re 

not. 

My hope is that we’re not in the job of character assassination 

to public servants. Clearly, some of us serve ourselves up to that 

from a standpoint of the media, and I will continue to defend the 

First Amendment right for them to say about me whatever they 

choose to say. I also reserve the right to point out when, in fact, 

they’re inaccurate, regardless of what they say. 

I thank you for very forcefully defending your ethics, more importantly for your willingness, in the face of the criticism of the reporters, and saying, ‘‘I’m still willing to serve myself up for public service,’’ and I appreciate that. 

I yield back, Mr. Chairman. 

Mr. LAVERTY. Thank you. 

Senator TESTER. Thank you, Senator. Just so you know, and so 

you know, Senator: our job is to ask questions and confirm. When 
35

perception becomes reality, sometimes that’s not fair and we have 

to make sure we get down to it, so we appreciate that. 

I have some questions, some more questions for you Joe, if I 

might. 

If I heard you correct, and so I’ll just have you repeat it: is one 

of the jobs of FERC to help protect consumers? 

Mr. KELLIHER. Exactly. I really think that is the primary task 

of the Commission is to guard the consumer from exploitation by 

non-competitive power and gas companies. 

Senator TESTER. Can you give me some examples of decisions 

that FERC has made in recent history where the wholesale market 

has tended to be monopolized and you’ve recognized that and made 

a decision? 

Mr. KELLIHER. First of all, one way is the way we’ve changed our 

market power test over time. It used to be, a number of years ago, 

the Commission had a market power test that, frankly, everyone 

passed, including companies with very large market shares. Now 

we’ve tightened up that test, we’ve raised the bar and we do deny 

market-based authorization of companies. If we find that a company has too large of a market share or that it can’t mitigate its 

market power, we deny its privilege to charge market-based rates. 

So, you could argue that maybe 10 years ago it was a right to get 

market-based rates, now it is a privilege and you have to jump over 

higher hurdles. 

Senator TESTER. Can you search into that mental data base and 

give me some examples where you’ve made a decision that has resulted in cost-based power? 

Mr. KELLIHER. We have denied market-based rates for Duke in 

the Carolinas. They had a market share exceeding 70 percent. We 

have had a number of companies surrender their market-based 

rates. Entergy surrendered its market-based rates. There’s probably at least a half dozen pretty significant companies that have 

lost or surrendered their market-based rate authority. 

Senator TESTER. Those decisions were based on what? 

Mr. KELLIHER. Based on a market-based rate test that we have 

been strengthening since the California and Western Power Crisis. 

Senator TESTER. Can you give me some of the criteria of that 

test, very briefly? 

Mr. KELLIHER. We’ve taken about four or five steps since then. 

We’ve tight, strengthened the reporting requirements under our 

market-based rate program. We changed the generation market 

power test. It used to be what’s called the old ‘‘hub-and-spoke’’ test. 

Everyone passed. Literally everyone passed—except a few Canadian companies—but literally every applicant passed, including 

companies with 70 percent market share. We have raised that, we 

now apply a screen. We look at 20 percent, 20 percent is our rough 

measure or proxy screen. We use it as a screen to say, ‘‘Does someone possibly have market power?’’ If they have 20 percent market 

share, that raises a flag, they might have market power. Then we 

drill down further. 

We also have a pivotal supplier screen that supposed to measure 

market power during peak periods. Again, it’s a flag, then if that 

flag goes up, we look harder, we drill down harder. We have, we 

now revoke market-based rates, something we didn’t used to do. 
36

We enforce the conditions of market-based rate authorization. It 

used to be companies would violate those conditions and continue 

to charge market-based rates. We’ve revoked, in the past 2 years, 

probably more than 200 companies’ market-based rate authorization. Because again, it’s a privilege, if they violate the conditions, 

we revoke the privilege. 

Senator TESTER. Were those screens in place when you made the 

decision on the PSCMCC rate case for Montana? 

Mr. KELLIHER. Yes, they were. 

Senator TESTER. Okay. 

Just quickly review, because this is an important issue to me, I 

think it’s an important issue to all Montanans. In October, the 

Public Service Commission of Montana, the Montana Consumer’s 

Council, filed for rehearing to argue back the case that the decision 

was made by FERC. They have not heard anything, as you explained earlier, and you’re obviously aware of it and I appreciate 

that. 

On June 7, 2007, and—just a couple months, maybe not even 

that, a month—the contract expires with our major generator in 

the State of Montana, significantly major generator. The impacts of 

this—of not rehearing this case could be incredibly significant depending on what happens when that contract is re-upped. I would 

just ask of you, because it’s very important to everybody, that you 

get back to me as quickly as possible—and the Montana Public 

Service Commission and the MCCM on when—on if that’s going to 

be reheard, that case, and when that would be. I would certainly 

appreciate that. Is that, could you give me any kind of timeline as 

when that might happen? When you might be able to get back to 

me? 

Mr. KELLIHER. I, can I respond in writing? Because I don’t know 

how quickly we could act and I have to—what I can do is promise 

to look, give a very hard look at the arguments raised by the Montana Public Service Commission. 

Senator TESTER. Okay, good. 

Going back to your first point—if your major reason for existence 

is to help ensure consumers get a fair shake, hopefully this will 

float to the top. Because I think that it’s very, very important. 

The last thing I would like to say is, is that I very, very much 

appreciate you fellows coming up here. I appreciate your public 

service. Whether I vote for your confirmation or not, that fact 

stands as true. I really want to thank you for taking the time. It’s 

hard to answer some questions and, quite frankly, it’s hard to ask 

questions too, like this. I really appreciate your forthrightness and 

appreciate your public service. So, thank you very much. 

Mr. KELLIHER. Thank you. 

Senator WYDEN [presiding]. I thank my colleague. 

I’m going to have a number of additional questions for you in 

writing, Mr. Laverty. One of them deals with the issue of questionable hiring, that’s this Denver Post, you know, article about hiring 

a personal friend of yours. 

I also am a little bit puzzled about this audit of your Department 

in Colorado. I got the impression from what you said that matters 

had all been resolved, but I’m looking at a press article on it. It 
37

seems to indicate that the audit won’t be finished until July. Is 

that right? 

Mr. LAVERTY. That’s correct, sir. 

Senator WYDEN. But you consider it resolved? 

Mr. LAVERTY. No, no. 

Senator WYDEN. That there won’t be any additional concerns reflected in the audit, is that your opinion? 

Mr. LAVERTY. Senator, I did not imply that the audit was resolved. The audit is a performance audit and the audit, based 

on——

Senator WYDEN. I understand that, but you don’t anticipate this 

audit, from your standpoint, raising additional questions about either your financial management, or your ethics, or anything of that 

sort. 

Mr. LAVERTY. No, sir. I believe that one of the outcomes of that 

audit would be that it will look at our internal control systems and, 

are the internal control systems adequate to do the kinds of things 

that we need to be doing? I believe that’s where it’s going to come 

out. 

Senator WYDEN. I’ll ask the additional questions for you in writing. 

Mr. LAVERTY. Certainly. 

Senator WYDEN. I want you to understand that I do not believe 

that I can vote for you at this time. I hope that there will be, in 

the other discussions that I think you and I are going to have, and 

in the responses you send me in writing, an opportunity for you to 

convince me that at this unique time in history, given that 

Abramoff, Griles, Julie McDonald—the list goes on and on, that 

you’re going to go in there and drain the swamp. You’re going to 

deal with what Mr. Devaney calls an ‘‘ethical quagmire.’’ And I 

think we didn’t get off to the best footing the other day because I 

thought that you would have at least read Mr. Devaney’s report, 

given the enormous impact it would have on your office, when we 

sat down. 

But let us proceed and I will ask the additional questions in writing of you. We’ll have future conversations, if you choose to do so 

and I’ll—let us leave it there, and we thank you and your family 

for being here today. 

Mr. LAVERTY. Thank you, Senator, and I look forward to having 

those conversations with you. 

Senator WYDEN. Very good. 

Mr. Kelliher, you and I talked as well. As you know, in Oregon 

folks are very concerned about the LNG situation. We are the location of two preliminary LNG projects, the proposed location of several more. Folks at home are concerned about the economic impact, 

the environmental impact. And certainly, their concern’s been 

heightened by the fact that under a provision in the Energy Policy 

Act of 2005, a provision I opposed, our State siting process was preempted and FERC was put in charge instead of having our State 

agencies in charge. 

So, I wrote you in March asking some questions about how the 

Agency intended to deal with those issues. For example, what analyses and analytical tools FERC would use to look at the safety of 

the projects. After the facility was approved and built, I wanted to 
38

know what FERC authority was there to make sure safety and security would be addressed. And I wanted to know how FERC would 

ensure that inadequate firefighting and other public safety resource gaps that were identified by the Coast Guard would, in fact, 

be filled, and what authority FERC would have to deal with it. 

The answers that we got, we didn’t feel were particularly responsive, and certainly folks in those communities didn’t feel they were 

responsive. The general response from the Department, as you and 

I discussed, was that somehow this would all be covered in a draft, 

environmental impact statement. 

So, my first question to you is: is there some reason why you can 

not state—you can do it in writing if you choose to—what FERC’s 

statutory authority is, at this point, to make sure that public safety 

measures necessary to make these projects safe are met? 

Mr. KELLIHER. First of all, as I said in my statement, FERC’s 

role when it comes to LNG projects—we are primarily a safety regulator. We’re not balancing the safety of a project versus the need. 

We look only at the safety of the project. 

If you look at what we did in Keyspan, a project in Providence, 

Rhode Island, New England obviously needs natural gas supplies. 

We didn’t balance the need for new natural gas in New England 

against safety. We viewed that the project didn’t meet our safety 

standards, we rejected it, notwithstanding the need. And, that’s the 

approach, the general approach we take in Oregon as well. 

So, we also have a responsibility under the Energy Policy Act to 

consult with State agencies. When an LNG project is proposed, the 

Governor of the State has a right, under the Energy Policy Act, to 

identify a State agency and FERC is required by law to consult 

with that State agency. 

Now the proposals in Oregon are newer than some of the other 

projects in other States and I would suggest, if, the goal is really, 

how do we closely coordinate between Federal and State agencies 

as these LNG projects are proposed in Oregon? Perhaps, it would 

make sense to sit, for the Federal, for FERC staff to sit down with 

other Federal agencies, as well as State agencies, and just have a 

general discussion of how do we coordinate as these projects are 

proposed? 

We do have a pre-filing process and we have a formal part of the 

process. The pre-filing process, to me, is very important because it’s 

an opportunity for State agencies, environmental groups, community, sister agencies to identify issues very early on in the process. 

Any issues that are raised by Oregon State agencies, we will address. 

Senator WYDEN. Well, feel free to take another crack at answering the letter because, I will tell you, even from a community 

standpoint, the idea of saying that this will all be dealt with sometime down the road in a draft EIS, doesn’t send much of a message 

that the agency is going to be proactive in the safety and other concerns that I’ve related. So, I hope you will take another crack at 

the letter, and particularly on laying out what FERC’s statutory 

authority is, to make sure public safety measures can be taken. I 

was going to ask you why you can’t explain the methodology 

FERC’s going to use to evaluate some of the particular safety concerns. I mean, they’re very concerned about tsunamis and earth-
39

quakes on the Coast. We have real scientific evidence to justify, you 

know, those concerns, and people looked at your response. I mean, 

we took it, we shared it with various people in the State and they 

said, ‘‘We can’t figure out why they won’t answer those questions.’’

Mr. KELLIHER. Can I just emphasize——

Senator WYDEN. Please. 

Mr. KELLIHER. The draft environmental impact statement is not 

the decisional document. It is the, it’s a staff recommendation, it’s 

the staff summary of the science and that is an opportunity for, 

yet, another round of public comment, and comment by State agencies. It’s only when we get to the stage of the final environmental 

impact statement, when we get the reaction of the DEIS, that then 

the instrument becomes part of the Commission’s decisionmaking. 

So, the DEIS, it’s not the last step, it’s something that we can then 

get reaction to. We have community hearings, we have local hearings on the DEIS. 

Senator WYDEN. So, with respect to earthquakes or tsunamis, 

you would just say it’s a preliminary kind of process and just wait 

to let it get started, and we’ll talk to you about it down the road? 

Mr. KELLIHER. Right. Those issues are raised in the pre-filing 

process; they will be addressed in the Draft Environmental Impact 

Statement. And, if people disagree with the Commission staff’s 

views of the science on those issues, I assume they will step forward and say, ‘‘No, you’re wrong in your conclusions here. You’re 

wrong in your recommendations there.’’ And, we would listen to 

those comments. We typically get thousands of pages of comments 

of a Draft Environmental Impact Statement, so it is, it’s really, I 

think, more the beginning of the process rather than the end of the 

process. 

Senator WYDEN. The other aspect of this that concerns me, is we 

were digging through the files and trying to get a sense of the history of the agency. You gave a speech not too long ago and you 

said, and I quote here, ‘‘We’re not an economic regulator when it 

comes to LNG, we are purely a safety,’’ you know, ‘‘regulator.’’

Mr. KELLIHER. Yes, sir. 

Senator WYDEN. What struck me, is given that statement, why 

you won’t answer some of these fundamental questions with respect to safety, and just sort of pushing them down the road. 

Now, I think we’ve almost gotten to the point where I can let you 

go as well. I think there’s one additional area I am concerned 

about, but I hope you will take another crack at that letter. Because I thought that it was constructed, the speech you gave, highlighting your safety concerns, but it’s hard to reconcile that with 

the answers we got in the letter, which by and large, said just wait 

for the Draft Environmental Impact Statement. 

You want to take a crack at that comment, about primarily being 

a safety regulator, and how you do it? 

Mr. KELLIHER. Sure, I, the distinction to me, if you look at how 

we regulate a pipeline—when we regulate a pipeline, we do look at 

what’s the need for the pipeline, what’s the need for the natural 

gas. We set a rate for it. So, we are regulating the economic viability of the project to some extent. When we look at an LNG project 

we’re not setting a rate, we’re not looking at what’s the need for 

natural gas. We look at it to some extent under NEPA, but when 
40

we’re deciding whether or not to authorize the project, it’s principally, ‘‘Does it meet our safety standard?’’ If not, can we condition 

it so it can meet our safety standard? And we routinely condition 

proposed LNG projects. 

There’s one project that we attached 93 conditions to, to protect 

safety, to protect the environment. So that’s a routine aspect of 

what we do, but we’re not regulating it to assure the economic viability of the LNG project. And, so that’s the distinction I’m trying 

to draw. And we do listen to the environmental and the safety considerations of State agencies, the community, environmental 

groups. 

Senator WYDEN. Just one last question for you, for this morning, 

Mr. Kelliher, and I will have some additional questions in writing. 

Now, given your initial set of answers to me, Draft Environmental Impact Statements are big deals. I mean, this is an important, you know, document. And, that in the answers to me, essentially, the questions the State has raised or I’ve raised, they’re 

going to be looked at there. 

But then Congressman Baird, who represents the Congressional 

District in Washington that’s across the Columbia River from one 

of the projects, wrote to you all asking to have the comment period 

for the draft EIS extended from 45 days to 90 days. But you wrote 

back denying his request. 

So, on April 9, 2007, the Oregon Department of Energy made a 

similar request; asked for the agency to extend the comment period 

for that particular document from 45 days to 120 days because a 

45–day review is insufficient for what we expect to be a voluminous 

and complex document. 

So we’ve got State agencies trying to cope with three LNG 

projects, and new pipelines that go with them. They’re doing the 

vast bulk of this work without being able to recover any of their 

costs through application fees and so they’re really strapped for resources. Do you expect to be denying the Oregon extension request, 

as well? 

Mr. KELLIHER. I’m not sure I can answer the question of what 

we’ll do specifically with respect to the Oregon request. 

Part of the difficulty is, if we waive deadlines for comments in 

one instance, we—as a practical matter—are obliged to waive them 

in every instance because we can’t, you know, the courts hold us 

to a standard where we grant a waiver in one case it, we, it pretty 

much becomes routine to routinely grant waivers. The deadlines 

end up being somewhat meaningless. 

What we try to do to compromise, is we agree to accept late comments. So there is a deadline, our general rule is not to waive the 

deadline, but we accept late comments. We’re currently doing that 

with respect to other LNG projects where, arguably, 2, 3 months 

after the deadline we’re still accepting comments. We’ll accept comments up to the point where we make the decision. If we do accept 

late comments, we weigh them. 

Senator WYDEN. I’ll have some additional questions for you. I do 

hope that you’ll be more specific in your responses to these additional questions. Again, to hear that the draft EIS is a big deal and 

then all of my constituents unhappy about how that’s being handled, as well, again just goes to the point that, communities just 
41

feel they’re getting rolled on these projects. I mean, they just feel 

that the special interests in Washington, DC just walk all over 

them. And I will just kind of leave both of you with an assessment 

of where we are. 

You two are going to be dealing with some of the most important 

domestic issues of our time. Mr. Laverty comes into a Department 

that has been riddled by scandal. That’s just a fact, that’s on the 

public record. You don’t have the Inspector General making statements like Mr. Devaney has, casually, and I want to hear how 

that’s going to be cleaned up, specifically. 

Mr. Kelliher comes in when there’s tremendous concern about 

energy prices shooting through the roof and folks look at what’s 

happened in the area of liquefied natural gas and they say, ‘‘The 

Federal Government took our authority away here at home and 

now we have people like Brian Baird and Ron Wyden asking questions.’’ They look at the answers that we’re getting and they’re not 

satisfied. 

So, we’re going to take another crack at this with both of you. 

I’m sure this has not been the most pleasant morning in the history of your lives, because Senators do have strong feelings about 

this topic and it comes because our constituents have strong feelings. 

So, I always like to have the witnesses have the last word. Is 

there anything, Mr. Laverty, or you Mr. Kelliher, would like to 

add? 

Mr. LAVERTY. Thank you Senator. I look forward to your questions and I want to be able to give you forthright answers that will 

respond to your concerns. If I need to follow back up with you personally, I would look forward to that opportunity. 

Senator WYDEN. Very good. 

Mr. Kelliher. 

Mr. KELLIHER. I just want to thank you for being so forthright 

and expressing your concerns and I’ll do my best to answer your 

questions. 

Senator WYDEN. Very good. The committee’s adjourned. 

[Whereupon, at 11:36 a.m., the hearing was adjourned.] 

(43)

APPENDIXES 

APPENDIX I 

Responses to Additional Questions 

RESPONSES OF R. LYLE LAVERTY TO QUESTIONS FROM SENATOR DOMENICI

NATIONAL PARK SERVICE CENTENNIAL INITIATIVE

Question 1. The Administration has proposed a $100 million Federal authorization 

to be used as incentive for collecting nonfederal matching funds for the centennial 

initiative. The funds would be used for signature projects at national park units 

throughout the country. 

What should be the role of the National Park Foundation, if any, in the National 

Park Service Centennial Initiative matching fund program? 

Answer. The National Park Foundation was established by Congress to raise private funds for National Park Service projects and should have a role in the matching fund program proposed in the Centennial Initiative. I understand that the Foundation is currently in the process of preparing a detailed Centennial Initiative fundraising plan for which it will seek approval at its August 2007 board meeting. If 

confirmed, I look forward to working with the Foundation, friends groups, and other 

partners on the Centennial Initiative. 

NATIONAL PARK VISITATION

Question 2. Visitation at national parks is an important source of revenue in gateway communities and the parks themselves. 

If you are confirmed, what would you do to increase both the number and diversity of visitors? 

Answer. As I mentioned during my confirmation hearing, I am sensitive to visitation patterns. I believe that for the National Park System to remain relevant, a 

strong advocacy must be maintained. Knowing who your visitors are, were, and will 

be is essential. The National Park Service will be conducting a comprehensive survey of visitors and non-visitors this Fall to learn more about their leisure activities 

and why they do or do not visit national parks. Based on the findings of this survey, 

the National Park Service will continue to provide a range of programs and amenities that appeal to a wide range of populations, such as various ethnic and racial 

groups, children, youth groups, seniors, urban and suburban dwellers. If confirmed, 

I will support these efforts to increase the number and diversity of visitors to our 

parks. 

SUITABILITY/FEASIBILITY STUDIES

Question 3. New park units often go through a 2-step process on the road to being 

designated as part of the national park system by Congress. The initial authorization requires a study to determine the suitability and feasibility of designation. The 

National Park Service is usually given 3 years from the time funds are made available to complete the study. 

Do you think this is a reasonable system, and if not, how would you propose to 

change it? 

Answer. I believe it is appropriate to carry out studies prior to designation of new 

units of the National Park System. Through these studies, the National Park Service determines whether an area is nationally significant and suitable and feasible 

for designation as a unit and, if so, whether the National Park Service is the most 

appropriate entity to manage the area. These studies also identify those areas that 

could best be preserved and managed by entities other than the Federal Govern-
44

ment. Studies also include information such as estimated costs, the strength of public support, and the likely involvement of partners, which assist Congress in making 

informed decisions about adding an area to the system and how it should be managed. 

SILVERY MINNOW

Question 4. Mr. Laverty, the federal government has been involved in extensive 

litigation regarding the preservation of the Rio Grande Silvery Minnow. In 2003, the 

Fish and Wildlife Service promulgated a Biological Opinion which contained reasonable and prudent alternatives to ensure the preservation of the species. 

Do I have your commitment that you will work with the USBR and the Corps 

of Engineers in order to ensure that the reasonable and prudent alternatives are 

met in a timely manner? 

Answer. If confirmed, I will continue the solid working relationship the Department has established with the Bureau of Reclamation, the Army Corps of Engineers, the State of New Mexico, and tribes to implement measures for the recovery 

of the species. It has been my experience that working cooperatively is the preferred 

method of Endangered Species Act implementation. While meeting the reasonable 

and prudent alternatives of a biological opinion is a requirement, it is my understanding that the Fish and Wildlife Service works in a cooperative manner with its 

fellow Federal agencies in fulfilling the Rio Grande Silvery Minnow Biological Opinion. 

Question 5. I created the Middle Rio Grande Endangered Species Collaborative 

Program in order to bring all parties together who would be affected by meeting our 

obligations under the Endangered Species Act. This program has been successful in 

avoiding new litigation over the Minnow. 

Do I have your commitment that the Fish and Wildlife Service will continue to 

be an active participant in the Collaborative Program? 

Answer. I am fully committed to the Collaborative Program’s continued success. 

It is my intention, if confirmed, to work with the Fish and Wildlife Service to ensure 

that this cooperative approach is continued. Throughout the nation, efforts to implement Endangered Species Act requirements benefit from multi-stakeholder collaboration such as the Middle Rio Grande Endangered Species Collaborative Program. 

It is my hope that these types of approaches will serve as models for other species 

conservation efforts. 

RESPONSE OF R. LYLE LAVERTY TO QUESTION FROM SENATOR DORGAN

Question 6. I am concerned about expanding prairie dog populations on the Dakota Prairie Grasslands for the potential reintroduction of the black-footed ferret. 

The prairie dog is the staple food source for the black-footed ferret. The Dakota 

Prairie Grasslands in North Dakota is very productive land for grazing cattle, and 

prairie dog colonies pose many problems for ranchers. I understand that the Dakota 

Prairie Grasslands are managed by the U.S. Forest Service, but it is also my understanding that the U.S. Forest Service must be in consultation with your position at 

the U.S. Fish and Wildlife Service to agree to undo a jeopardy opinion that would 

amend their Land Management Plan and your Recovery Plan to add North Dakota 

to the list as a potential recovery site for the black footed ferret. I would ask for 

your commitment to work closely with the U.S. Forest Service to undo the jeopardy 

opinion and see that the necessary steps are taken to ensure that North Dakota is 

not included as a potential site for black footed ferret recovery under your Endangered Species Act Recovery plan or the U.S. Forest Service Land Management Plan 

for the Dakota Prairie Grasslands. Would you be willing to make that commitment? 

Answer. I have checked with the Fish and Wildlife Service and been informed 

that a jeopardy opinion has not, in fact, been issued with regard to the Forest Service’s Land Management Plan. If confirmed, I would certainly be willing to work with 

all parties to see if there are ways in which this particular case could be resolved 

to the satisfaction of all parties. 

RESPONSES OF R. LYLE LAVERTY TO QUESTIONS FROM SENATOR WYDEN

Question 7. As you know, the Inspector General for the Interior Department completed a report on ethics issues involving Ms. MacDonald and her interference in 

scientific assessments and determinations of the Fish and Wildlife Service. It’s apparent from the IG’s report, which you have now read and reviewed, that Ms. MacDonald improperly intervened in a number of the Fish and Wildlife Service’s Endangered Species Act determinations as well as other matters. If confirmed as Assistant 

Secretary, what actions will you take to determine whether or not the agency deci-
45

sions that Ms. MacDonald participated in are indeed valid and based on the agency’s scientific evidence? 

Answer. If confirmed as Assistant Secretary, I will immediately meet with Fish 

and Wildlife Service Director Dale Hall to determine the scope and magnitude of 

the agency decisions influenced by Ms. McDonald. Based on a rapid assessment involving agency staff, with Director Hall’s personal involvement, I would seek to determine which project decisions could be inconsistent with scientific analyses. The 

focus and importance of this assessment is to develop a comprehensive inventory of 

decisions that may or may not have been included in Inspector General Devaney’s 

report. 

I would ask Director Hall to review decisions determined to have been based on 

compromised science and develop immediate recommendations for action. 

Question 8. The Union of Concerned Scientists released a survey in 2005 of 1,400 

scientists at the Fish and Wildlife Service, which you would direct as Assistant Secretary. These are biologists, ecologists, botanists and other government scientists. 

The Union asked those who studied endangered species if they had been directed, 

for non-scientific reasons, to find a species to not be in jeopardy and therefore not 

in need of protection, despite all scientific evidence to the contrary. Nearly half of 

the scientists responded that, yes, they had been ordered to compromise their work 

that way. One-third of all the scientists said they are not allowed to do their jobs 

honestly at Fish and Wildlife because of political influence and conflicting business 

interests that control the agency’s agenda. If you are confirmed as Assistant Secretary, what actions will you take to restore the independence of agency scientists 

under your authority? 

Answer. If confirmed as Assistant Secretary, immediately upon taking office, I 

will do the following to effect a culture change: 

On my first day in office I will meet with the Department’s ethics officer. I will 

have her personally review/reiterate the Department’s ethics standards with me. 

I will meet with my policy staff and the Department’s Solicitor to review all rules 

and regulations regarding the protection and disclosure of information received by 

the Office. 

I will explain that I expect full adherence to the highest ethical standards, including not sharing non-public information with outside parties. 

I will explain that any contacts they have with field personnel at either the Fish 

and Wildlife Service or the National Park Service regarding questions of science 

must and will be through established organizational channels, and only with my 

prior approval. 

I will explain that my policy staff is not to ask for or direct any change or modification in scientific findings by either agency. 

I will establish and apply a code of conduct for my office that requires everyone 

to be treated with dignity and respect. Any type of abusive behavior toward anyone 

will not be tolerated. 

I will meet with the Directors of the Fish and Wildlife Service and the National 

Park Service and make clear that:

• Contact between my policy staff and agency personnel on management or regulatory actions will go through established organizational channels; 

• I expect the Directors of FWS and NPS to personally ensure agency decisions 

are supported with credible scientific information, that as appropriate, is peer 

reviewed; 

• My policy staff are not to ask any of the agency staff to change scientific findings; 

• No staff, policy or career, are to act abusively toward any person—whether government employee or member of the public and, if there is any indication of inappropriate behavior, it is the Directors’ responsibility to inform me immediately; 

• They are to personally advise their management teams of my expectations for 

each of them in adhering to these principles; and 

• Any violations of these principles are to be reported immediately to me personally by the agency Directors for appropriate action.

In the event of any violation of these principles, I will not hesitate to ensure that 

appropriate action is taken. 

Question 9. As reported in the Denver Post on February 15, 2007, Great Outdoors 

Colorado (GOCO), which provides state lottery money for the state parks, withheld 

$8.5 million from your agency because your department could not account for past 

spending and didn’t seem to have financial controls in place. The Post cites a February 1 Great Outdoors Colorado memo stating that ‘‘Several times over the last 

year, the ac counting/finance staff of parks at all levels was unable to articulate 
46

basic accounting principles involving the GOCO bills.’’ In your testimony before the 

Committee you indicated that you believed that these issues had been resolved. 

What actions did you take to address the issues raised by GOCO concerning your 

department’s accounting deficiencies? 

Answer. The following deficiencies were identified and addressed as part of 

GOCO’s concerns for accounting: Identified underperforming staff, clearly identified 

GOCO’s data needs, and created the proper quality controls to ensure the long term 

success of this relationship. 

A number of events transpired in late 2005 and early in 2006 that significantly 

impacted the Division’s GOCO accounting and reporting activities. Since none of 

these factors were reflected in the Denver Post article, it is important to provide 

the context leading to the actions that have addressed the issues. 

The Division experienced several significant changes in the Financial Services 

(FS) unit. Based on very serious performance deficiencies, the CFO began addressing performance accountability. The Controller and a lead accountant both resigned 

their positions early in 2006. The CFO had to rely on the GOCO accounting tech 

to perform the necessary GOCO billing and reconciliation tasks until more senior 

accounting personnel could be hired. After a lengthy hiring process, the new Division Controller assumed his duties in June of 2006. The CFO immediately assigned 

him the tasks of evaluating and improving the GOCO billing and reconciliation 

process. 

Under the ‘‘Guiding Principles’’ that the GOCO board enacted to define the Division’s policy in how to prioritize, spend and account for GOCO funding resources, 

there was a stipulation that ‘‘old’’ GOCO money had to be spent before ‘‘new’’ money 

could be spent. 

This triggered a massive effort on the part of State Parks in December 2005/January 2006 to reallocate expenditures at Cheyenne Mountain from newer GOCO 

grants to older grants and Lottery funds. It was imperative for the process to be 

completed to release funding so that construction on Cheyenne Mountain could proceed without delay. Parks staff worked closely with GOCO on this process and 

brought it to a successful conclusion. This was a complex task with a large number 

of grant budget lines, contract awards, task orders and payments involved, where 

the process and the results would ultimately have to meet both GOCO and audit 

standards. 

The Division’s CFO scheduled meetings with GOCO’s CFO and accounting staff 

to solicit input from GOCO on how to improve the reporting processes, given the 

Division’s personnel situation. The desired outcome was to define the reporting requirements—different for base and large scale projects—that would meet GOCO’s 

reporting and audit needs. 

A meeting with GOCO staff in August, 2006 produced a substantive agreement 

on this issue and the Division worked diligently to produce these work products, 

both interim and permanent. The products included a temporary set of ‘‘payment 

adjustment record’’ forms for the Cheyenne Mountain Golden Triangle contract, 

which was due and delivered to GOCO in September 2006. The fact that a difference existed between some invoices submitted by contractors and what was ultimately paid to the contractor caused GOCO great frustration. In the summer of 

2006, this became a major issue ultimately involving the DNR Controller. 

The DNR Controller communicated in a letter to GOCO on June 20, 2006 that 

it is not uncommon in the construction industry for disagreements to arise regarding project completions. Payments are determined on the basis of the project manager’s assessment of the quality and acceptability of materials furnished, work performed, and the rate of progress of the work, all interpretations of the plans and 

specifications, and the acceptable fulfillment of the contract. Payments are not made 

on the basis of the contractor’s subjective assessment of these same issues as reflected in invoices. Thus, payments are made on those items where there is agreement and, where there is no agreement, the balance deferred and subjected to further resolution and/or negotiations. 

The DNR Controller concluded, based on the terms of the Memorandum of Understanding (MOU) between the Division and GOCO, that the MOU only requires a 

monthly billing statement to GOCO, identifying the total expenditures to date, along 

with copies of the COFRS accounting reports to support the amount billed to GOCO. 

She also concluded that, since COFRS is the official financial record of the state, 

information contained in the accounting reports should be sufficient for GOCO to 

make the determination that a vendor has been paid by the Division, and that reimbursement from GOCO to the Division is due. In a follow-up e-mail from GOCO’s 

CFO, she referenced additional documentation requirements contained in the Legacy/Large Scale grant agreements—correctly so—and State Parks has responded to 

these additional requirements. 
47

State Parks agreed to develop a single format for pay sheets that would include 

a ‘‘payment adjustment record’’ and be used on all legacy/large scale funded grants 

such as Cheyenne Mountain, St. Vrain and future projects. Division staff continues 

to consult with GOCO staff in the development process of format to assure that 

GOCO accounting data needs are met. The Division Controller met with the GOCO 

CFO and accounting staff the week of November 13, 2006 to develop even closer 

communications and cooperation in defining these and other needs. 

Another work product requested by GOCO and delivered by the Division was expenditure by fund and year for Cheyenne Mountain since the inception of the 

project. This was requested by GOCO to review match funding for legacy/large scale 

projects. This report was generated in short order and delivered in its final form 

to GOCO on October 5, 2006, with a positive reception by GOCO’s CFO. 

On September 13, 2006, the Division’s CFO and GOCO’s CFO agreed that GOCO 

would pay the May and June bills with the understanding that the Division would 

be providing with the July and subsequent billings, a summary billing statement 

with a formula error corrected. The Division’s GOCO Accounting Tech and seasonal 

staff spent considerable time (approximately three weeks) and effort, in an attempt 

to isolate and correct the formula error, without success. At that time the Division’s 

CFO decided that it would be better to re-develop the billing summary in an 

MSAccess format. This would eliminate the error and add additional reporting capabilities to adjust to possible future GOCO requests for changes in reporting detail 

and formats. 

GOCO was informed of this decision and the impact it would have on receiving 

the July and subsequent GOCO billings completed and submitted. It should be 

noted that the summary spreadsheet with the formula error was developed by Division GOCO accounting staff no longer with the Division. 

Just after this effort began, in the third week of September, the Division’s GOCO 

Accounting tech had to attend to a critical family issue that demanded her full attention. She was out of the office for nearly four weeks. Although she tried to work 

on the report at home as time would permit, the effort was seriously delayed. Again, 

GOCO was informed of the situation and the consequential impact on the Division’s 

ability to meet its time commitment on the billing summary report and associated 

July and subsequent billing submittals. The Division eventually met with GOCO to 

present the draft MSAccess report on Monday, November 13, 2006 and to discuss 

the submittal of July, August, September and October billing reports. 

The CFO has met with his FS Management team to define and pursue a strategy 

to cross train available staff and build process redundancy within the organization. 

He has also expressed his intent to add a much needed quality control and assurance component to the GOCO billing process. The addition of another budget/accounting FTE in fiscal year 2007-8, requested in the Division’s fiscal year 2007-8 

FTE Decision Item, and recently approved by the legislature, will add much needed 

staff to implement these changes. 

After the review and a subsequent meeting on November 16, 2006, with the Division’s Controller, GOCO’s CFO agreed to accept the Division’s July, August and September billings with the currently available backup and to manually adjust any inconsistencies as done previously. The Division would get the substantial outstanding 

revenue recorded in COFRS, and GOCO would get the funds transferred and off 

their books. The Division agreed to have the billings completed and submitted to 

GOCO by November 30, 2006. The Division’s October GOCO billing would be submitted no later than December 14, 2006. 

The Controller worked essentially full time to resolve the GOCO impasse and develop a billing and reconciliation process, with supporting documentation and reports to meet GOCO’s billing verification, reconciliation and audit requirements. He 

was assigned the primary lead on all GOCO accounting and financial interface and 

communications events and activities. The Controller has successfully resolved the 

GOCO accounting and reconciliation issues, which led to successful approval and release of the fiscal year 2007-2008 spending plan. 

In summary, filling critical positions, such as the Division’s Controller and Lead 

Accountant with skilled and highly qualified individuals, combined with defining reporting needs with GOCO has successfully addressed these concerns. 

Question 10a. As reported in the Denver Post on March 24, 2007, Harris Sherman, the director of the Department of Natural Resources asked for an audit of your 

department in response to concerns raised by GOCO. Information obtained by my 

staff indicated that GOCO agreed to release its 2007 funding to your department 

based only after this audit was arranged. The Auditor has characterized this as ‘‘a 

full-blown audit of the Division of Parks,’’ which is expected to begin shortly. Your 

testimony before the Committee suggested that you requested this audit and that 

you characterized it as a ‘‘performance review.’’
48

* Graphics and information have been retained in committee files. 

What was your role in requesting this audit? 

Answer. In a February meeting with the Executive Director, prior to the GOCO 

Board meeting, I recommended that we ask the State Auditor to conduct a performance audit to ensure that the Division’s internal controls were in order. This recommendation was a proactive effort to review our existing internal control systems 

and determine if there are other improvements the Division should take, such as 

training, staffing, and project management. 

Question 10b. What is the exact scope of this audit and when will it be completed? 

Answer. I understand the audit team has met with Department of Natural Resources and Division personnel to define the scope of the audit. The completion 

would be determined by the review plan once the scope has been completely defined. 

Question 11a. The Denver Post also reports that you used $5,000 in state funds 

to buy a horse for you to ride and which you later had your Department sell to your 

son-in-law. When my staff followed up with the Colorado Department of Natural Resources official who oversaw your agency’s budget, he confirmed that against the advice of the Department of Natural Resources, you used $5,000 in state money to buy 

a horse so you could participate in a private trail ride—and when a legislative panel 

ordered you to sell the horse, you sold it not at public auction, as state property 

usually is disposed of, but to your son-in-law. The article states that Mr. John Nelson ‘‘. . . said he sold Laverty the horse because Laverty was becoming a member 

of the Roundup Riders of the Rockies—a 59 year-old fraternity of influential men 

from around the country who every July ride Colorado’s trails.’’ This April 10, 2007 

Denver Post story goes on to quote defending the purchase of the horse for this purpose—‘‘It’s certainly an appropriate use,’’ said Laverty. ‘‘If the agency had a horse 

and that was an opportunity to interact with folks who had an interest in what our 

business is all about, there’s nothing wrong with that.’’ In your testimony before the 

Committee, you indicated that the purpose of the purchase was not related to your 

use or participation in trail riding, but to establish an equestrian unit within your 

department. 

Please provide copies of your budget, decision memoranda, business plan, organization chart, and other relevant documents establishing an equestrian unit and allocating funding for it, including the purchase of horses. 

Answer. I have attached to this document information responsive to your request.*

The equestrian unit was to be a resource assigned to the Senior Ranger. The attached organization chart* updated to reflect the current staffing at Chatfield shows 

a PM III. This position has the responsibility for visitor services and park operation. 

The equestrian unit would have been staffed by the ranger unit. 

Included below is the preliminary budget assessment for the unit operations. This 

adjusted estimate was included in the parks operating budget for fiscal year 2005.

COLORADO STATE PARKS ESTIMATED EQUESTRIAN UNIT

PROGRAM EXPENSES 

Amount 

Blacksmith Services: 

Shoeing every 6 to 8 weeks, beginning April through November: 

Estimated cost per visit: $70

Estimated visits: 6

Estimated costs ....................................................................................... $420.00

Veterinarian Services ..................................................................................... 300.00

Feed .......................................................................................................... 300.00

Total ...................................................................................................... $1,020.00

Question 11b. Did you or did you not intend to use the horse for the purpose of 

your own participation in trail rides exclusively or in conjunction with other uses? 

Answer. The horse was not acquired for my exclusive use. The horse was purchased to establish an equestrian program for a variety of park operations, including visitor contacts in our urban parks as well as backcountry patrols in our mountain parks. The primary objective of the mounted ranger patrol was to provide officer presence to the busiest areas of our large metro parks. Other park and law enforcement agencies have found that a mounted ranger provides a highly effective 

tool for positive visitor contacts. 
49

The value of a mounted ranger has been tested throughout the country in metropolitan communities and urban parks. Large park areas, like Chatfield and Cherry 

Creek with large open space and extensive trail systems are settings where mounted rangers can patrol more effectively than rangers on foot or with motorized vehicles. Other park units and law enforcement agencies reinforce the effective point of 

visitor contact with a mounted ranger. 

In 2004 the Division conducted a series of town meetings throughout the State 

to receive public input regarding state park facilities and services. Based on input 

the Division received during the town meetings, the public ranked trails and 

trailheads for hiking and horseback riding as a very high priority. Having park 

managers ride with equestrian organizations in the field to discuss State park trails, 

trailheads and corrals is extremely effective, as we have learned from participation 

in similar activities with hikers, ATV and snowmobile organizations. 

To clarify the context, the legislature did not order the Division to sell the horse. 

A member expressed a comment that I felt could put some of the Division’s programs at risk. I discussed the comment with the Division’s executive team and determined selling the horse was the appropriate action. 

Question 11c. Did you or did you not receive advice from the Department of Natural Resources to desist from buying the horse? If so, what was that advice and by 

whom was it provided? 

Answer. I did receive a memorandum from the Department Controller expressing 

concern over the purchase based on his concern over personal use. I cannot recall 

any correspondence or communication with advice to desist from the purchase. I 

personally met with the Controller and discussed the equestrian program in the Division’s park operations. We discussed the program benefits and advantages of a 

mounted patrol in our metropolitan parks. Subsequent to that discussion the purchase order was approved by the Department of Natural Resources Contracting Officer. Question 11d. In your testimony before the Committee you indicated that the resale of the horse to your son-in-law was discussed with State procurement and contracting officials and they agreed that there were no requirements or restrictions 

that would otherwise apply to or restrict such a sale. Please identify the procurement and contracting officials with whom you consulted. 

Answer. The Department of Natural Resources Controller and the Department of 

Natural Resources Contracting Officer. 

Question 12a. The Denver Post also reported that in 2003 you changed the job 

specifications for the post of your agency’s chief financial officer. The Denver Post 

reports that you reduced the classification from ‘‘manager’’ to ‘‘budget analyst II,’’ 

which required less education and experience—so you could a hire a personal 

friend—Elling Myklebust—from among 47 applicants for the job. 

What role, if any, did you play in establishing or modifying the job specifications 

for the position of chief financial officer? 

Answer. First I need to correct the Denver Post report on the changes in the position that took place, dating back to 2003. The Denver Post article is in error in reporting the position was changed from a manager to a budget analyst II. The position was changed from a manager to a Budget Analyst IV. 

After reviewing the strengths and weaknesses of the Division’s organization, in 

early 2003 I adjusted work load assignments based on individual’s skills and qualifications. I found that the existing CFO, with no background in park administration 

or natural resources, had been assigned the portfolio that included the division’s 

field operations and law enforcement program. I reassigned those program oversight 

responsibilities to the Deputy Director. 

This organizational adjustment resulted in changing the position description to 

accurately reflect the position responsibilities. The adjustment resulted in a classification change. At that time, the position classification was changed from a Manager series to a Budget Analyst IV. To suggest that this adjustment was changed 

so I ‘‘could hire a personal friend’’ is unfounded and has no factual basis. 

In early 2005, upon receiving notice of the CFO’s planned retirement in May, I 

began to review the demands of the Division and evaluate the skill needs of the position. Based on that evaluation with members of the executive team, I personally 

worked with the Department’s Human Resources staff to develop a position description that addressed the division’s needs. Based on the Division’s strategic plan, one 

important goal was to develop some financial stability. The Division’s needs were 

for strategic financial systems management, with the objective of strengthening the 

Division’s financial situation. 

The CFO retired on May 30, 2005. On May 6, 2005, the position was advertised 

as a Budget Analyst IV, with the working title of Chief Financial Officer. 

Question 12b. If so, at what point in the personnel hiring process did this occur? 
50

Answer. The change in position responsibilities took place two years before the 

former CFO retired. Upon receiving notification of the planned retirement of the incumbent, I initiated the review and analysis of the position requirements. This review began approximately three to four months before the position was advertised. 

It is common practice when positions become vacant to review the position descriptions for accuracy and to accommodate agency needs. 

Question 12c. And, if so, did you know at the time that Elling Myklebust or any 

other individual known to you was applying, or had applied, for the position? 

Answer. No. 

Question 12d. At any point, did you suggest to Elling Myklebust or any other individual that they should apply for this position? 

Answer. No. 

Question 12e. What role did you play in the review of, and/or final selection of, 

applicants for the position of chief financial officer? 

Answer. The State of Colorado has a very rigorous and structured personnel testing process. The Department’s Human Resources division manages this entire process. Human Resources issues vacancy announcements and screens the applicants to 

determine which candidates meet the minimum qualifications. Following that screen 

and evaluation, Human Resources administers and scores a written test. The test 

questions are developed by the Human Resources division based on the position description. 

Following the scoring and evaluation of the written test, the candidates go 

through an oral test with a panel of Human Resources and subject matter experts 

from other divisions in the Department. From this panel, generally the top three 

candidates are then submitted to me for selection. Individuals involved in this evaluation panel included the Department’s Budget Office and the Department’s Controller and the Department’s Director of Human Resources. This panel developed 

the recommendations and submitted three candidates for me to consider. It was at 

this point, and this point only, that I saw the selection options. I had no knowledge 

of which candidates successfully passed the written test. I had no knowledge of 

which candidates the oral testing panel interviewed. After interviewing the three 

candidates, I selected Mr. Myklebust after considering his qualifications, background, and the needs of the Division based on the position description. 

Question 13a. As discussed by Sen. Burr during your appearance before the Committee, you are apparently a member of many outside boards and organizations. The 

Denver Post reports that you participated in overseas trips related to these memberships and that overseas trips were paid for from non-state funds. The April 10, 2007 

Denver Post article indicates that you believed that there was nothing improper 

with such trips—‘‘It’s an opportunity to market Colorado,’’ he said. ‘‘I just view it 

as part of the business.’’

Did you, at any point during your tenure as director of the Department of Parks, 

receive payment for, or in-kind travel or services, related to non-official activities 

or events? 

Answer. Senator Burr was correct that I currently serve or have served on several 

volunteer advisory Boards. These include The Colorado Fourteeners Initiative, The 

Colorado Youth Corps Association, Volunteers for Outdoor Colorado the Society of 

American Foresters Council, and the Salvation Army Denver Metropolitan Advisory 

Board. If the Denver Post article implied my participation in overseas travel was 

associated with any of these organizations, the article is incorrect. 

As the Director of State Parks, in 2005, I was asked by the U.S. Forest Service 

to participate in a technical assistance trip to support ongoing USAID Lebanon Mission projects. The request was supported by the Ambassador as an opportunity to 

extend the U.S. Mission and presence in Lebanon. Because of my background in 

wildland fire and community fire assessments, I was asked to provide an overview 

and recommendations regarding strategies for creating defensible space in the 

urban communities in Lebanon. Additionally, we were asked to suggest recommendations for the development of an organization to support the planning, development, and construction of 300 km trail through the country. The expenses of 

this technical assistance were funded through USAID. 

In March 2006, I was asked again by the U.S. Forest Service, with the Ambassador’s concurrence, to participate in a technical assistance trip to support ongoing 

USAID Mission in Lebanon projects. The purpose was to provide an assessment and 

recommendations on the condition of Italian Stone Pine in Lebanon. Pine nut production is an integral part of many community economies. The request was approved by the Governor’s office. Travel expenses were reimbursed through USAID 

funds. 

I was asked by the U.S. Forest Service at the invitation of USAID to participate 

as a presenter in a USAID training program on tourism development and integrated 
51

* Information has been retained in committee files. 

park resource planning. This program in Arusha, Tanzania, was for USAID in country personnel, designed to equip them to work with country personnel to accomplish 

USAID mission objectives. As above, this travel request was approved by the Governor and expenses reimbursed through USAID funds. 

Because of our work on community involvement with several large trail projects 

here in Colorado, I was asked to return to Lebanon in the late fall of 2006 to conduct a community capacity workshop on trail planning and design. As above, this 

request was approved by the Governor and expenses were reimbursed through 

USAID funds. 

Since December of 2005, I have participated in quarterly Society of American Foresters Council meetings and receive reimbursement for travel expenses. 

Question 13b. If so, when and from whom? 

Answer. I believe the responses I have provided above answer this question. 

Question 13c. What State of Colorado or agency conflict of interest or ethics requirements or requirements pertaining to outside positions applied to you in your 

position as the head of the Department of Parks and do any of those requirements 

address the receipt of payments or in-kind services to you for non-official functions? 

Answer. I have attached to the end of this document a copy of the State of Colorado’s conflict of interest policy.* The travel described was approved by the Governor and is considered official travel. 

Question 13d. At any point during your tenure as director of the Department of 

Parks did you seek or request an ethics or conflict of interest ruling with regard 

to your participation in, or receipt of payments or in-kind travel or services related 

to your participation in nonofficial functions? If so, when and to whom did you make 

those requests and regarding what activities? 

Answer. All of my travel during my State employment was associated with my 

official agency responsibilities. I did not participate in any non-official functions that 

resulted in payments related to my involvement except for my participation with the 

Society of American Foresters. I discussed my involvement on the volunteer advisory boards described above with the Department Executive Director. It is not uncommon to have Department employees serve on advisory boards. 

Question 14a. Part 2635 of Title 5 of the U.S. Code of Federal Regulations establishes standards of ethical conduct for employees of the Executive Branch of the 

United States Government. Section 2635.802 states that an employee shall not engage in outside employment or any other outside activity that conflicts with his official duties. 

During the final 10 year period while you were an employee of the U.S. Department of Agriculture did you engage in outside employment or any outside activity 

that conflicted with, or could appear to conflict with, your official duties? If so, 

please identify those activities. 

Answer. No, I did not. 

Question 14b. During this period, did you seek or request an ethics or conflict of 

interest review or advice or approval for any membership in, or participation in activities sponsored by, outside organizations? If so, when and to whom did you make 

those requests and regarding what activities? 

Answer. Over the course of my career I did participate in presentations and attended conferences sponsored by a number of outside organizations, such as The Society of American Foresters, the National Association of State Foresters, and the 

National Recreation and Parks Association. I discussed each these invitations with 

my supervisors to ensure there was no conflict with my official duties. 

Question 15a. Subpart B of Part 2635 of Title 5 of the U.S. Code of Federal Regulations establishes restrictions on receipt of gifts from outside sources. As a general 

rule, employees are prohibited from receiving any salary or contribution to or supplemental salary and are prohibited from seeking, accepting, or agreeing to receive 

or accept anything of value in return for being influenced in the performance of an 

official act. 

During the final 10 year period while you were an employee of the U.S. Department of Agriculture did you seek, request, or receive a salary, gift, or other contribution from an outside organization? If so, what did you receive and from whom? 

Answer. I did receive several pens, cups and tee shirts over the course of the 

years as tokens of appreciation for participation in various training sessions. I believe most of these items were given to all presenters. I have presented at the National Association of State Foresters. I believe I have a pin and a pen from them. 

I presented at a meeting of the NASLOR representatives and received a pen from 

them. 
52

Question 15b. At any point during this period, did you request an ethics or conflict 

of interest review or advice or approval for acceptance of any salary, gift or contribution from any outside organization? If so, when and to whom did you make those 

requests and regarding what activities? 

Answer. Each year during my performance review I discussed ethics and conduct 

with my supervisor. I was aware of my responsibilities as a Federal employee of 

Subpart B of 2635 of Title 5 of the U.S. Code of Federal Regulations and never 

placed myself in that position. During the last 10 years with the U.S. Department 

of Agriculture, I reviewed my conduct and ethics responsibilities with the Chief of 

the Forest Service, and received my ethics training, as required. 

RESPONSES OF R. LYLE LAVERTY TO QUESTIONS FROM SENATOR SALAZAR

Question 16. There has been tremendous concern that documents leaked from 

within the Department of the Interior and published in news reports indicate that 

the administration is considering major policy changes that would influence virtually every aspect of the Endangered Species Act. Some have characterized the proposed changes as tantamount to a full re-write of the law. While the administration 

has said that the leaked documents do not reflect the Department’s intentions, I 

think you can understand why we in Congress would be concerned. 

If you are confirmed, are you willing, in an effort to find common ground, to commit to sharing specific text of any potential revisions to the Endangered Species Act 

regulations with Members of Congress and stakeholders well in advance of any formal proposed rulemaking? 

Answer. Like Secretary Kempthorne, I am committed to finding common ground 

to resolve difficult issues. I understand it has been the longstanding policy of the 

Department that drafts of proposed regulations are not shared outside of the Department because of the internal deliberative nature of rule development. I am advised, however, that it is the Department’s general policy to notify Congress and 

stakeholders of key points of major initiatives, such as this, in advance of their release. Should I be confirmed, I will keep Congress informed in advance of any rulemaking decision. 

Question 17. If confirmed, what specific steps will you take to ensure that the Department promptly addresses the concerns regarding the use or misuse of science 

within the Department, as identified by Inspector General Earl Devaney? 

Answer. If confirmed as Assistant Secretary, I will immediately meet with Fish 

and Wildlife Director Dale Hall to determine the scope and magnitude of the agency 

decisions influenced by Ms. McDonald. Based on a rapid assessment involving agency staff, with Director Hall’s personal involvement, I would seek to determine which 

project decisions could be inconsistent with scientific analyses. The focus and importance of this assessment is to develop a comprehensive inventory of decisions that 

may or may not have been included in Inspector General Devaney’s report. 

I would ask Director Hall to review decisions based on compromised science, and 

develop recommended actions. 

If confirmed as Assistant Secretary, immediately upon taking office, I will do the 

following to effect a culture change: 

On my first day in office I will meet with the Department’s ethics officer. I will 

have her personally review/reiterate the Department’s ethics standards with me. 

I will meet with my policy staff and the Department’s Solicitor to review all rules 

and regulations regarding the protection and disclosure of information received by 

the Office. 

I will explain that I expect full adherence to the highest ethical standards, including not sharing non-public information with outside parties. 

I will explain that any contacts they have with field personnel at either the Fish 

and Wildlife Service or the National Park Service regarding questions of science 

must and will be through established organizational channels, and only with my 

prior approval. 

I will explain that my policy staff is not to ask for or direct any change or modification in scientific findings by either agency. 

I will establish and apply a code of conduct for my office that requires everyone 

to be treated with dignity and respect. Any type of abusive behavior toward anyone 

will not be tolerated. 

I will meet with the Directors of the Fish and Wildlife Service and the National 

Park Service and make clear that:

• Contact between my policy staff and agency personnel on management or regulatory actions will go through established organizational channels; 
53

• I expect the Directors of FWS and NPS to personally ensure agency decisions 

are supported with credible scientific information, that as appropriate, is peer 

reviewed; • My policy staff are not to ask any of the agency staff to change scientific findings; • No staff, policy or career, are to act abusively toward any person—whether government employee or member of the public and, if there is any indication of inappropriate behavior, it is the Directors’ responsibility to inform me immediately; • They are to personally advise their management teams of my expectations for 

each of them in adhering to these principles; and • Any violations of these principles are to be reported immediately to me personally by the agency Directors for appropriate action.

In the event of any violation of these principles, I will not hesitate to ensure that 

appropriate action is taken. 

Question 18. Over the last several years, the Administration’s budget requests for 

the National Park Service have consistently fallen short of the operations and maintenance needs in our Parks. The National Parks Conservation Association estimates 

that the annual operating shortfall for the national parks is over $800 million. This 

year, however, I was pleased to see that under Secretary Kempthorne’s leadership 

the Administration’s request begins to address the shortfall in our Parks. Can you 

please share with me your views on the funding needs in our Parks, and tell me 

where you believe our national parks should fit among federal budget priorities? 

Answer. I believe a priority for the National Park Service is to fulfill the vision 

of the National Parks Centennial Initiative, which will help us prepare the National 

Park System for the 21st Century. As part of the Centennial, the Administration 

is requesting operating increases which will allow us to improve the capabilities in 

parks to address visitor needs, enrich learning opportunities, and better preserve 

historic and natural treasures. In addition, I support the President’s proposal for a 

Centennial Challenge matching fund that will encourage our partners to donate 

funding for signature projects and programs. 

Question 19. Will you advocate for a larger sustained investment in our national 

parks over the coming years as a part of the Administration’s National Park Centennial Initiative? 

Answer. Yes, I will. The President’s Centennial Initiative proposes a $3 billion investment in our national parks over the next 10 years. I believe this level of investment will prepare our parks for their second century of preservation and public enjoyment. 

Question 20. Just last year, I and many of my colleagues, including Senator Alexander, fought hard to ward off attempts to weaken protections on Park resources 

by rewriting the time-tested National Park Service management policies. We successfully defeated these destructive attempts and, with the signature of Secretary 

Kempthorne, ended up with a new draft of the management policies that strengthens and clarifies the Park Service’s conservation mandate. Could you share with the 

Committee your views on the mission of the National Park Service and on the role 

that conservation should play in the management of Park resources? 

Answer. I concur with Secretary Kempthorne’s position that when there is a conflict between protection of resources and their use, conservation will be predominant. 

RESPONSES OF R. LYLE LAVERTY TO QUESTIONS FROM SENATOR CANTWELL

Question 21. Mr. Laverty, as you may know, Mount St. Helens in southwest 

Washington is currently a National Volcanic Monument managed by the Forest 

Service. The Gifford Pinchot National Forest, citing a money shortfall, recently announced that it will close Coldwater Ridge Visitor Center and scale back visitor 

services around Mount St. Helens. I have been approached by some of my constituents who advocate that it should be made a National Park. Could you please tell 

me what additional resources DOI would bring to Mount Saint Helens as a National 

Park that are not currently provided by the Forest Service as it managed as a National Monument? 

Answer. While I am unaware of all the resources the Forest Service allocates for 

the management of Mount St. Helens, I can only comment on the manner in which 

national parks are funded. National parks receive their own allocations for park operations and are eligible for system-wide funding such as repair/rehab and cyclic 

maintenance. National parks also retain certain fees, including franchise fees generated through concessions management, entrance fees, and expanded fees for camping and similar activities. 
54

However, as I understand it, the National Park Service has its own large maintenance backlog and constraints on operational activities. It is not clear to me that 

moving the area to the National Park Service would necessarily result in more resources being available. 

Question 22. Recent media reports and a DOI Inspector General investigation revealed that former Assistant Secretary for Fish, Wildlife and Parks Julie MacDonald misused her position to influence endangered species protection, rewrite scientific reports, intimidated U.S. Fish and Wildlife Service employees, and colluded 

with industry lawyers to generate lawsuits against the Fish and Wildlife Service. 

In fact, the OIG found that Ms. MacDonald’s conduct violated the Code of Federal 

Regulations (C.F.R.) under 5 C.F.R. § 2625.703 Use of Nonpublic Information and 

5 C.F.R. § 2635.101 Basic Obligation of Public Service, Appearance of Preferential 

Treatment. Given the importance of the scientific process being free from political 

influence, what is your plan to ensure that employees of the U.S. Fish and Wildlife 

Service do not misuse their posts to influence scientific reports and will abide by 

professional and legal standards? 

Answer. On my first day in office I will meet with the Department’s ethics officer. 

I will have her personally review/reiterate the Department’s ethics standards with 

me. I will meet with my policy staff and the Department’s Solicitor to review all rules 

and regulations regarding the protection and disclosure of information received by 

the Office. 

I will explain that I expect full adherence to the highest ethical standards, including not sharing non-public information with outside parties. 

I will explain that any contacts they have with field personnel at either the Fish 

and Wildlife Service or the National Park Service regarding questions of science 

must and will be through established organizational channels, and only with my 

prior approval. 

I will explain that my policy staff is not to ask for or direct any change or modification in scientific findings by either agency. 

I will establish and apply a code of conduct for my office that requires everyone 

to be treated with dignity and respect. Any type of abusive behavior toward anyone 

will not be tolerated. 

I will meet with the Directors of the Fish and Wildlife Service and the National 

Park Service and make clear that:

• Contact between my policy staff and agency personnel on management or regulatory actions will go through established organizational channels; • I expect the Directors of FWS and NPS to personally ensure agency decisions 

are supported with credible scientific information, that as appropriate, is peer 

reviewed; • My policy staff are not to ask any of the agency staff to change scientific findings; 

• No staff, policy or career, are to act abusively toward any person—whether government employee or member of the public and, if there is any indication of inappropriate behavior, it is the Directors’ responsibility to inform me immediately; 

• They are to personally advise their management teams of my expectations for 

each of them in adhering to these principles; and 

• Any violations of these principles are to be reported immediately to me personally by the agency Directors for appropriate action.

In the event of any violation of these principles, I will not hesitate to ensure that 

appropriate action is taken. 

Question 23. Several years ago, Congress passed bipartisan legislation to expand 

the boundary of Mount Rainier National Park, along the Carbon River. The purpose 

of this expansion was to alleviate flooding problems along the Carbon River road, 

by relocating a campground out of the flood-prone area, thereby saving taxpayer 

funds for road reconstruction. The President’s FY 2008 budget request included no 

land acquisition funds to acquire private lands from willing sellers within the authorized National Park boundary. In the National Park Service’s nationwide ranking for land acquisition projects, where is this project ranked? How much would be 

needed to acquire all of the private lands within the Park expansion. If Congress 

provides funds in the FY 2008 Interior appropriations bill, could the NPS obligate 

these funds in FY 2008 to acquire the privately-owned lands? 

Answer. I am not aware of the specifics of this project. If confirmed, I will look 

into this issue to determine the priority for this particular project within the National Park Service’s land acquisition program, if funds could be obligated in a timely manner, and get back to you with this information. 
55

Question 24. As you know, Secretary Kempthorne recently announced a ‘‘Centennial Challenge’’ for the national parks. In the past, the NPS has been criticized for 

failing to follow through on promises related to the parks, in particular President 

Bush’s 2000 campaign promise to eliminate the NPS maintenance backlog. Please 

describe how you plan to implement this initiative and what you believe it could 

mean for our nation’s parks? How would you respond to critics that do not believe, 

based on the Administration’s record to date, that help for the parks might be forthcoming? 

Answer. Like Secretary Kempthorne, I am committed to fulfilling the vision of the 

National Parks Centennial Initiative, which will help prepare the National Park 

System for the 21st Century. The Centennial Initiative calls for a $3 billion investment in parks over the next ten years, and its successful implementation requires 

action of both the Executive and legislative branches of government coupled with 

support from philanthropic partners. As part of this effort, the President’s fiscal 

year 2008 budget proposes the largest operating budget in national park history and 

the National Park Service’s largest single-year increase. I commit to you that I will 

work to ensure that the increase in operating funds provides for improvement in visitor needs, enriched learning opportunities, and better preserved historic and national treasures. I am aware that the Administration has forwarded a legislative 

proposal that would create the National Park Service Centennial Challenge Fund, 

which would provide the necessary mechanisms that allow federal funds to match 

philanthropic donations in order to fund $100 million in signature projects and programs as proposed by the President. If confirmed, I look forward to working with 

you on these efforts. 

Question 25. Our National Park System was established to protect and preserve 

the natural resource gems of this country. How do you propose to maintain the natural resource values of these gems for future generations, given the massive maintenance backlog and external and internal threats from incompatible uses? 

Answer. I am in agreement with Secretary Kempthorne that, when there is a conflict between protection of resources and their use, conservation will be predominant. Protecting the natural resource values of our national parks is vitally important. The President’s fiscal year 2008 budget proposes the largest operating budget 

in national park history and the National Park Service’s largest single-year increase. We also need to think creatively about the future. The Centennial Initiative 

sets the foundation for enhancing these national treasures by establishing long-term 

partnerships with the American people that will result in a $3 billion investment 

in parks over the next ten years. The Administration has forwarded a legislative 

proposal that would create the National Park Service Centennial Challenge Fund 

that would provide the necessary mechanisms to allow Federal funds to match philanthropic donations as part of this $3 billion commitment. 

Question 26. Are there currently any plans to drill for oil and gas or allow mining 

within 20 miles of any U.S. National Park? Can you please provide your views on 

oil and gas and mining development within 20 miles of U.S. National Parks? 

Answer. I am not personally aware of any plans to drill for oil and gas or to allow 

mining in the proximity of any national park. One of the challenges of managing 

the national parks is recognizing that there are many development uses going on 

outside of park boundaries. If confirmed, I would also work with park neighbors, including other Federal agencies, State or local entities, or private parties, to seek to 

ensure that there is minimal impact from such external development on park resources. 

Question 27. Over the longer term, projected budget shortfalls could cause refuges 

to cut 565 ‘‘essential’’ staffing positions, create a $2.5 billion maintenance backlog 

and leave 57 percent of refuge operations at a fiscal loss by 2013. Our national refuges play an importance role in preserving habitat for endangered, threatened and 

other critical species as well as providing hunting and fishing opportunities. What 

steps will you take to address this? 

Answer. I am committed to supporting the National Wildlife Refuge System, including ensuring that it continues to play an important role in conserving fish and 

wildlife and habitats and providing fishing and hunting opportunities. I understand 

that the Fish and Wildlife Service is evaluating staffing and workforce realignments 

to evaluate ways to improve effectiveness and efficiency. If confirmed, I will work 

with the Fish and Wildlife Service to evaluate the results of this process in order 

to ensure continued support for the refuge system. 

Question 28. A number of measures to develop the FY 2009 budget have been 

adopted, including consolidating multiple refuges around the country. There is great 

concern that these actions have seriously compromised the ability to fulfill the refuges’ mission. What actions will you to take to reverse this trend? 
56

Answer. I understand that the Fish and Wildlife Service is evaluating staffing and 

workforce realignments to evaluate ways to improve effectiveness and efficiency. If 

confirmed, I will work with the Service to evaluate the results of this process, including consolidations, and ensure that they do not compromise the mission of the 

refuge system. 

Question 29. The U.S. Fish and Wildlife Service is a critical partner in working 

with state and local governments, industry, businesses, private landowners, and the 

conservation and environmental communities to identify, restore and protect habitats in order to conserve imperiled species that depend upon those habitats. For several years, there has been a ‘‘no-acquisition or expansion’’ policy that hamstrings the 

ability for the Service to work with partners to create new refuges, expand current 

refuge boundaries, or acquire key refuge parcels through the Land and Water Conservation Fund. How do you propose to change this current policy to allow the Service to move forward as an active partner in protecting important species habitat in 

this country? 

Answer. Secretary Kempthorne has been working within the context of the Administration’s budget process to prioritize land acquisition in refuges and national 

parks. It is my understanding that the Fish and Wildlife Service has the opportunity to acquire lands through the Land and Water Conservation Fund and 

through other programs, such as the Migratory Bird Conservation Account. In addition, the Fish and Wildlife Service has multiple grant programs that leverage Federal funding for acquisition of habitat with matching efforts of States, tribes, and 

others. If confirmed, I plan to advocate for these programs in order to ensure that 

the Fish and Wildlife Service continues to be an active partner in protecting habitat. 

Question 30. I often hear from my constituents in Washington state that the Endangered Species Act permit process takes too long because there are not enough 

Fish and Wildlife Service personnel available to process applications in a timely 

manner. I am concerned that many projects are delayed or never completed due to 

this lack of resources. What specifically will you do to ensure that FWS gets the 

operational funding and staff to meet its mandated responsibilities under the Endangered Species Act? 

Answer. I fully appreciate the importance of the Endangered Species Act and the 

important role of the Fish and Wildlife Service in implementation of that Act, and 

of the need to ensure funding for all of the Department’s priority programs. If confirmed, I will work with the Fish and Wildlife Service to explore ways to provide 

a more effective and less time-consuming permit process, including promoting the 

Fish and Wildlife Service’s collaborative approach to species protection. 

Question 31. In recent weeks, the Department of Interior has issued a fact sheet 

and held several meetings with Congress regarding a leaked draft of Endangered 

Species Act proposed regulatory changes. Both the recently issued DOI fact sheet 

and the leaked draft language propose to make significant changes to the implementation of the ESA. What is the expected timeframe for the issuance of proposed 

changes to current ESA regulations? In moving an ESA regulatory package forward, 

how should the Department of Interior work with Congress to ensure these proposed 

changes are consistent with Congressional intent under the ESA? 

Answer. It is my understanding that the Department has not made any final decision on whether to move forward with proposed changes to the ESA implementing 

regulations. Like Secretary Kempthorne, I am committed to finding common ground 

to resolve difficult issues. I understand it has been the longstanding policy of the 

Department that drafts of proposed regulations are not shared outside of the Department because of the internal deliberative nature of rule development. I am advised, however, that it is the Department’s general policy to notify Congress and 

stakeholders of key points of major initiatives, such as this, in advance of their release and, should I be confirmed, I will keep Congress informed in advance of any 

rulemaking decision. 

Question 32. In the Fiscal Year 2008 Budget, the Department of Interior zeroed 

out funding for two U.S. Fish and Wildlife Service programs that have met with 

great success in the State of Washington—the Landowner Incentive Program and 

the Private Stewardship Grant Program. Based on the Department’s budget justification for no longer funding these programs, Interior argued the Landowner Incentive Program and Private Stewardship Grant Program were duplicative with 

funding for the Refuge System, the North American Wetlands Conservation Act, and 

the Partners for Fish and Wildlife Service Program, none of which fund large scale 

restoration efforts on private lands for threatened, endangered and at-risk species. 

What are your thoughts on the importance of providing federal funding toward supporting voluntary efforts by private landowners to conserve habitat for imperiled 

species? Additionally, how should limited federal funds for private land restoration 

be prioritized within states and regions for funding conservation needs? Would you 
57

support targeting these funds toward state and regional priority areas determined 

to be in need of targeted restoration and conservation funding by federal, state, and 

local partners? 

Answer. Partnering with others to leverage available Federal funding for habitat 

conservation and protection is an important and powerful strategy. It is a key tool 

for the Secretary, and it promotes strong collaborative relationships with States, 

tribes, private landowners and others. Since a significant proportion of wildlife are 

found on private lands, these efforts are vital to attain species conservation goals. 

A number of the Department’s partnership programs do prioritize efforts to target 

priority areas and, if confirmed, I intend to continue this in order to advance the 

Department’s conservation goals. 

Question 33. Clearly climate change will impact the goals and management needs 

of our National Wildlife Refuges and National Parks. What strategies or plans (or 

processes to develop plans) would you initiate to deal with the impacts to the NWRS 

and NPS of climate change over the next twenty years? 

Answer. I understand that Secretary Kempthorne has established a Global Climate Change Task Force within the Department. It is my intention, if confirmed, 

to work closely with the Secretary, that task force, and the Directors of the Fish 

and Wildlife Service and National Park Service on developing strategies for dealing 

with the impact of climate change on the missions of those agencies. The Department’s task force will focus on translating generic research results into a form that 

meets the specific needs of the Department. The task force will also address land 

and water management and will assess and recommend actions to be taken by the 

Department to adapt to the changes anticipated. Finally, it will look at legal and 

policy issues and will review the various documents prepared by the Department 

with an emphasis on how the changes noted above should be discussed in those documents. 

RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR BINGAMAN

Question 1. In the Energy Policy Act, Congress amended the Federal Power Act 

to give the Commission stronger authority to review mergers of utilities. Our view, 

based in part on the abysmal record of affiliate abuse during the late Nineties and 

early part of this century at companies such as Westar and Allegheny, was that existing FERC cross-subsidization rules were inadequate to replace important protections for consumers that were being lost with the repeal of the Public Utility Holding Company Act. We required the Commission to make a finding that there would 

be no harmful cross-subsidization or encumbrance of assets as a result of utility 

mergers. The Commission’s merger rule-making is not clear on the point and there 

have been no mergers that raise cross-subsidization concerns since then, so it is difficult to determine what your view as to how to implement this authority would be. 

Do you believe that pre-existing FERC cross-subsidization rules are sufficient to 

make an affirmative finding that not harmful cross-subsidization will result from 

mergers? 

Answer. The Energy Policy Act of 2005 (EPAct 2005) strengthened the ability of 

the Commission to prevent the exercise of market power by expanding our FPA section 203 review authority to encompass certain transfers of generation-only facilities 

and certain holding company mergers and acquisitions. I believe the Commission’s 

expanded merger review authority improves our ability to discharge our duty to protect customers against the exercise of market power. After enactment of the law, 

one of our earliest initiatives was a rulemaking implementing the changes to section 

203, and we adopted our final rule by unanimous vote. Among other things, the 

final rule requires section 203 applicants to demonstrate through a detailed showing 

that no harmful cross-subsidization or encumbrance of utility assets will result from 

a proposed merger, acquisition or disposition. 

While EPAct 2005 expanded the scope of the Commission’s section 203 authority, 

it also largely left intact the Commission’s three-part public interest test established 

in its 1996 Merger Policy Statement. Under that test, the Commission analyzes the 

impact of a proposed transaction on competition, rates and regulation. 

As you know, the new law made an important change to the public interest test 

by requiring the Commission to make specific findings that a proposed transaction 

will not result in cross-subsidization of non-utility associate companies within the 

holding company system or the pledge or encumbrance of utility assets for the benefit of an associate company, unless consistent with the public interest. Preventing 

cross-subsidization is not a new responsibility for the Commission; it has been a 

fundamental duty since 1935, a duty we discharge whenever we set rates. In fact, 

prior to EPAct 2005, the Commission conditioned market-based rate approvals on 
58

1Keyspan, 117 FERC Paragraph 61,080 (2006). 

compliance with cross-subsidization conditions with respect to power and non-power 

goods and services transactions involving jurisdictional market-based sellers of electric energy. It also conditioned merger approvals involving registered holding companies on compliance with specific cross-subsidization restrictions involving nonpower goods and services transactions between holding company members; and following EPAct 2005 and the repeal of PUHCA 1935, the Commission announced in 

an order on the National GridKeySpan Corporation merger application that it would 

apply these cross-subsidization restrictions on all future mergers.1 However, complying with an explicit statutory requirement to prevent cross-subsidization at the 

point of a merger or other corporate transaction is a new responsibility to us. 

To explore how we can best discharge our new responsibility to make cross-subsidization findings at the time of a merger, as well as address other issues raised 

by the repeal of PUHCA 2005, the Commission, when it issued Order Nos. 667 (implementation of PUHCA 2005) and 669 (implementation of FPA section 203 amendments), stated that it would hold a technical conference within one year of the effective date of PUHCA 2005 and the section 203 amendments. The Commission held 

such conferences on December 7, 2006 and March 8, 2007, and obtained both written and oral comments from interested persons. In particular, the Commission 

asked detailed questions about cross-subsidization protections and ring-fencing 

measures at the state level when state regulators review proposed mergers, and 

whether additional generic cross-subsidization protections might be needed at the 

Commission level. Some of these questions related to the level of deference we 

should afford our state colleagues in this area, since the subject of any safeguards 

against cross-subsidization, such as ring fencing, bears on state jurisdiction. 

The technical conference discussion of cross-subsidization issues included participants with a wide range of views. Importantly, it included state regulators from 

states with strong ring fencing prohibitions. The sense of the majority of participants at the technical conference was that the Commission should not assume regulatory failure by the states, and instead should focus on filling a regulatory gap; the 

Commission should fashion policies complementary to state regulation and not 

adopt generic, ring fencing measures that preempt state authority. However, where 

states lack authority to prevent cross subsidization, I believe the Commission must 

act. In my view, there is a need for additional regulatory action to fill this regulatory gap. The Commission is currently considering options on how best to fill this 

regulatory gap. 

In the meantime, we are carefully evaluating all section 203 filings, including 

merger filings, to assess potential cross-subsidy issues and ensure that customers 

are adequately protected. In addition, I note that we have proposed to strengthen 

cross-subsidy rules for market-based sellers in our generic rulemaking on marketbased rate criteria. 

Question 2. A couple of years ago, the Commission circulated a draft rule that 

dealt with the conditions under which you would review contracts to determine if 

rates, terms, and conditions of service were legal. In that rule, you expressed the 

view that, unless it was contrary to the public interest not to do so, you would be 

barred from re-examining contracts, either on your own motion or upon complaint 

by affected parties. This view seemed to me to turn the Federal Power Act on its 

head and eliminate your authority to ensure that rates are just and reasonable and 

not unduly discriminatory. It was particularly troublesome that this proposal would 

have eliminated the rights of affected parties other than the signers of the contract 

to seek review of rates by the Commission under sections 205 and 206. I know that 

you did not finalize that rule, but if it is being implemented on a case by case basis, 

that is just as troublesome. Is it your view that you are barred from re-examining 

contracts to be sure that they remain just and reasonable unless such review could 

meet a supposedly almost insurmountable public interest test? 

Answer. It is not my view that the Commission is barred from reviewing contracts 

to assure they are just and reasonable, and, in my view, the public interest standard 

is not insurmountable. 

The Commission’s proposed rule regarding Mobile-Sierra issues proposed to clarify 

ambiguities in the law, thereby providing customers and sellers greater certainty regarding how their contracts would be treated by the Commission. The central issue 

addressed in the proposed rule was the interpretation of contracts that are not clear 

on whether the parties wish to be bound by the just and reasonable standard or, 

alternatively, the public interest standard. The Commission proposed that, in the 

narrow situation where the parties failed to express their intent on this issue, the 
59

2Public Utility Dist. No. 1 of Snohomish County, Wash. v. FERC, No. 03-74208 (9th Cir. December 19, 2006), and California Public Utils. Comm’n v. FERC, No. 03-74207 (9th Cir. December 19, 2006). 3Southern Company Services, 60 FERC Paragraph 61,273 (1992), order denying reh’g, 67 

FERC Paragraph 61,080, at 61,227-28 (1994), citing Papago Tribal Utility Authority v. FERC, 

723 F.2d 950 (D.C. Cir. 1983); Southern Company Services, 119 FERC Paragraph 61,065 at P 

42 (2007). 4Maine Bridgeport Energy, LLC, 118 FERC Paragraph 61,243 at P 41-42 (2007). 5Maine Public Utilities Commission v. FERC, No. 05-1001 (D.C. Cir. June 30, 2006). 6 Northeast Utilities Service Co., 55 F.3d 686, 690 (1st Cir. 1995); Texaco Inc. v. FERC, 148 

F.3d 1091, 1096 (D.C. Cir. 1998). 

public interest standard should apply. The U.S. Court of Appeals for the Ninth Circuit recently adopted that position.2

Apart from this narrow issue, the just and reasonable standard will continue to 

apply in many cases and, even when it does not, I do not believe the public interest 

standard is ‘‘practically insurmountable.’’ Rather, we retain ample authority to protect customers in all cases. For example, the just and reasonable standard will apply 

any time the parties agree to that standard in drafting their contracts. As a general 

matter, the just and reasonable standard also will apply to transmission or transportation contracts entered into under Commission-approved open access tariffs. 

It is also important to emphasize that the Commission has refused and will continue to refuse to be bound to the public interest standard where such standard is 

not appropriate. For example, the Commission has declined to be bound by the public interest standard when the parties seek to apply the just and reasonable standard to themselves.3 The Commission has declined to be bound by the public interest 

standard when transmission owners have entered into agreements that significantly 

impact third parties or the marketplace as a whole.4 The Commission also has declined to be bound where generators and an ISO or RTO have entered into mustrun contracts that significantly impact third parties.5

Finally, even when the Commission agrees to be bound to the public interest 

standard, I do not believe that standard is practically insurmountable to overcome. 

The Commission has reformed contracts under the public interest standard and 

been upheld by the courts.6 Moreover, contract reform under the public interest test 

is not limited to the three criteria in the original Mobile and Sierra decisions—

where the existing rate structure might impair the financial ability of the public 

utility to continue its service, cast upon other consumers an excessive burden, or 

be unduly discriminatory. We will, in all cases, continue to fulfill our obligations 

under the Federal Power Act and Natural Gas Act to protect customers from exploitation by sellers of electricity or natural gas. 

Question 3. Please provide the Committee with a summary of the Commission’s 

implementation or use of the new or clarified authorities provided in the Energy 

Policy Act of 2005 related to the siting, construction, expansion, or operation of LNG 

terminals, including any implementation problems. 

Answer. Section 311(d) of EPAct 2005 directed the Commission to establish mandatory procedures requiring prospective LNG facility operators to undergo a minimum six month period of pre-filing review by the Commission prior to filing an application for authorization to site and construct an LNG facility. Such procedures 

were to be established within 60 days of the enactment of EPAct 2005. The Commission issued its unanimous final rule (Order No. 665) on October 7, 2005 (Pre-Filing 

Procedures for Review of LNG Terminals and Other Natural Gas Facilities). 

Because the pre-filing process had been in use as a voluntary program since 2002, 

the industry and agency response was generally favorable. Many agencies that had 

previously participated in the process were encouraged to see regulations giving additional structure to the program and establishing timeframes for applicant submissions. Similarly, the industry accepted the regulations as evidence of the Commission’s commitment to transparency and consistency of process. 

In addition, on October 19, 2006, the Commission issued a final rule (Order No. 

687) implementing section 313 of EPAct 2005 (Coordinating the Processing of Federal Authorizations for Applications under Sections 3 and 7 of the Natural Gas Act 

and Maintaining a Complete Consolidated Record). The rule established regulations 

governing the Commission’s authority to (1) set a schedule for federal agencies, and 

state agencies acting under federally delegated authority, to reach a final decision 

on requests for federal authorizations necessary for proposed NGA section 3 or 7 gas 

projects and (2) maintain a complete consolidated record of all decisions and actions 

by the Commission and other agencies with respect to such authorizations. 

EPAct 2005 stated that a key part of the Commission’s role as lead agency for 

National Environmental Policy Act (NEPA) compliance was to set a schedule for the 

issuance of all federal authorizations that was both expeditious and in compliance 
60

with federal law. In compliance with NEPA, the Commission works with cooperating 

agencies to establish a schedule for the completion of the environmental review and 

to ensure that the environmental document can be used by the other agencies to 

satisfy their own NEPA requirements. 

In order to ensure that other agencies are positioned to act within the Commission’s established timeframe and to compile the consolidated record, the new regulations impose filing requirements on agencies issuing federal authorizations. Starting 

with the issuance of the proposed rule in May 2006, the Commission staff began 

meeting with industry and agencies to engage in a dialogue about the requirements 

of the Rule. This outreach effort is ongoing and is being accomplished by staff 

through project-specific discussions, participation in conferences, and through discussions with individual agencies. 

Throughout our discussions with state and federal agencies we have stressed 

what Order No. 687 does and does not do. Section 311 of EPAct 2005 is very clear 

that the rights of states under the Coastal Zone Management Act, the Clean Air 

Act, or the Federal Water Pollution Control Act are not affected by the Act. Similarly, Order No. 687 is clear that the states’ issuance of delegated federal authorizations under those statutes is not preempted, nor is any statutory timeframe affected 

by the Commission’s establishment of a schedule for completion of the environmental review or the schedule for issuance of federal authorizations. 

Question 4. Please provide a status report on pending LNG terminal applications, 

applications that have been withdrawn and applications that the Commission has 

approved since the enactment of EPAct 2005. In your opinion, will we have adequate LNG re-gasification capacity to meet future natural gas demand? 

Answer. The lists that follow this discussion show the terminals (including expansions) that the Commission has approved since the enactment of EPAct 2005 (August 8, 2005) and those applications for new terminals and terminal expansions that 

are pending before the Commission. No applications filed with the Commission for 

the siting of LNG facilities have been withdrawn. The Commission has denied an 

application by KeySpan to convert an existing LNG storage facility in Providence, 

RI, into an LNG terminal, capable of receiving waterborne shipments of LNG, due 

to safety concerns. This exemplifies the Commission’s primary role as a safety regulator in processing applications to site new LNG terminals and to expand existing 

LNG terminals. 

In its role as a safety regulator, the Commission does not participate in the planning of adequate LNG capacity, but I will offer my opinion on the adequacy of regasification capacity. The Energy Information Administration of the U.S. Department of Energy, in its Annual Energy Outlook 2007, estimates that by 2030, the 

U.S. will need almost 21 billion cubic feet per day of regasified LNG to meet total 

estimated demand of about 81 billion cubic feet per day. This means that LNG will 

account for over 25 percent of our natural gas supply by 2030. Currently, the U.S. 

has a maximum LNG regasification capacity of 5.8 billion cubic feet per day. The 

Commission has approved regasification capacity of 29.3 billion cubic feet per day 

at new and expanded LNG facilities. Seemingly, when this approved capacity is 

added to existing regasification capacity it would appear that there will be more 

than enough to satisfy future natural gas demand. However, I note that this will 

only occur if the LNG terminals operate at a very high capacity. Practically speaking, LNG terminals in the U.S. and worldwide do not operate at high capacity at 

all times due to the competitive world market where, like any commodity, LNG 

tends to move to the markets where prices are highest. Further, there is no guarantee that every LNG terminal that the Commission approves will be constructed. 

In sum, I do not believe that we currently have adequate LNG regasification capacity to meet future demand. However, given that our primary role is that of a 

safety regulator, the Commission does not engage in planning of LNG capacity, 

whether on a national or regional basis. To the extent the market responds with 

additional LNG proposals, the Commission stands ready to process them on a timely 

basis.
61

NEW TERMINALS APPROVED SINCE ENACTMENT OF EPACT 2005 (COMMISSION ONLY) 

Company/LNG Project 

Deliverability 

(billion 

cubic feet 

per day) 

Storage 

Capacity 

(billion 

cubic feet) 

Docket No Order Dates Projected In- Service Date 

Weaver’s Cove Energy, LLC, Fall River, MA ............................... 0.80 4.40 CPO4-36 .............. 07/15/05 ............... 2010Sempra Energy, Port Arthur Terminal Project, Port Arthur, TX 

(Phase I & II).

3.00 20.28 CP05-83 ............... 6/19/2006 ............. Winter 2010

Winter 2015

Crown Landing LLC, Logan Township, NJ .................................. 1.20 9.20 CPO4-411 ............ 6/20/2006 ............. 4th Qt 2008

Cheniere’s Creole Trail LNG, LP Creole Trail LNG Project, 

Cameron, LA.

3.30 13.50 CP05-360 ............. 6/15/2006 ............. Early 2009

Gulf LNG Energy, LLC, Pascagoula, MS ..................................... 1.50 6.80 CP06-12 ............... 2/16/2007 ............. Nov-09Bayou Casotte Energy LLC, Casotte Landing LNG Project, 

Pascagoula, MS.

1.30 10.10 CP05-420 ............. 2/16/2007 ............. Mar-10

Total ...................................................................................... 11.10 64.28

TERMINAL EXPANSIONS APPROVED SINCE ENACTMENT OF EPACT 2005 (COMMISSION ONLY) 

Company/LNG Project 

Deliverability 

(billion 

cubic feet 

per day) 

Storage 

Capacity 

(billion 

cubic feet) 

Docket No Order Dates Projected In- Service Date 

Sabine Pass LNG, L.P., Sabine Pass, LA (Phase II) .................... 1.40 10.10 CP05-396 ............. 6/15/2006 ............. Apr-09Freeport LNG Development, L.P., (Cheniere), Freeport, TX 

(Phase II).

2.50 3.40 CP05-361 ............. 9/26/2006 ............. Winter 2009

Cameron LNG, LLC (LNG), Hackberry LNG Terminal Expansion, Hackberry, LA. 1.15 3.40 CP06-422 ............. 1/18/2007 ............. 2010Dominion Cove Point LNG, LP, Cove Point Expansion, Cove 

Point MD.

0.80 6.80 CP05-130 & 132 6/15/2006 ............. Sep-08

Total ...................................................................................... 5.85 23.70
62

PENDING APPLICATIONS FOR NEW TERMINALS (COMMISSION ONLY) 

Company/LNG Project 

Deliverability 

(billion 

cubic feet 

per day) 

Storage 

Capacity 

(billion 

cubic feet) 

Docket No Projected In- Service Date 

Gulf Coast LNG Partners Project *Calhoun LNG, Port Lavaca, TX ...................... 1.00 6.80 CP05-91 .................. Winter 2009Sound Energy Solutions *(Mitsubishi), Long Beach LNG Terminal, Long Beach, 

CA.

0.70 3.50 CPO4-58 ................. 2009

Broadwater LNG *Long Island Sound, NY ............................................................... 1.00 8.00 CP06-54 .................. 2010Northern Star LNG—Northern Star Natural Gas, LLC, Bradwood, OR ............... 1.00 6.80 CP06-365 ................ 2010Quoddy Bay, LLC, Pleasant Point, ME ..................................................................... 2.00 10.10 CP07-38 .................. 2010Downeast LNG, Inc, Robbinston, ME ........................................................................ 0.50 6.80 CP07-52 .................. 2010Sparrows Point LNG, AES Sparrows Point LNG, KKC, Baltimore, MD ............... 1.50 10.10 CP07-62 .................. 2010Jordan Cove Energy Project, L.P.,** Jordan Cove LNG, Coos Bay, OR ................. 1.00 6.80 PF06-25 .................. 2010

Total ................................................................................................................... 8.70 58.90

* Draft Environmental Impact Statement issued. ** Pre-filing. 

PENDING APPLICATIONS FOR TERMINAL EXPANSION 

Company/LNG Project 

Deliverability 

(billion 

cubic feet 

per day) 

Storage 

Capacity 

(billion 

cubic feet) 

Docket No Projected In- Service Date 

Southern LNG (Elba Island Expansion III), Elba Island, GA ................................. 0.90 8.44 CP06-474 ................ 2010

2012
63

Question 5. According to your testimony, one of your ‘‘institutional goals’’ is to improve the relationship between FERC and the states. EPAct 2005 added a provision 

to the Natural Gas Act (Section 3A. State and Local Safety Considerations) directing 

the Commission to consult with States regarding State and local safety considerations prior to approving an LNG terminal application. The provision also requires 

applicants to use the pre-filing process under NEPA to address state and local concerns before and application is filed. In your opinion, have these provisions improved communications between the States, FERC and applicants and resulted in 

state and local concerns being addressed? Please provide specific examples. 

Answer. Section 311 of EPAct 2005 amended the Natural Gas Act to codify the 

consultation process with state agencies regarding safety considerations and produced a definite improvement in the communications between the Commission, the 

states, and the applicants for LNG terminals. State and local safety concerns are 

now being addressed much earlier in the review process, and the Commission has 

an established framework for the parties to follow that ensures that state and local 

safety concerns are properly considered. 

Specifically, the Governor of a state in which an LNG terminal is proposed is directed to designate a state agency for the purposes of consulting with the Commission on these matters. This designated agency may also provide the Commission 

with an advisory report on its safety considerations which the Commission must respond to before reaching a decision on the proposal. 

The Commission has received five applications for LNG terminals since the 

issuance of Commission’s regulations governing the pre-filing process in Order No. 

665. In each of these cases, the Governor of the affected state designated an appropriate agency and the Commission staff began working with that agency during the 

pre-filing process to ensure that the state’s concerns were identified and addressed 

during the early review stages. The requirement that applicants use the pre-filing 

process leads to earlier identification of the issues and is providing us opportunities 

to seek solutions alongside state agencies. There has been an increase in the level 

of participation from state resource agencies opting to cooperate with the Commission in conducting environmental reviews and preparing environmental impact 

statements. Subsequent to the filing of applications for the five terminals, each of 

the designated agencies filed an advisory report on state and local considerations. 

For both the proposed LNG proposals in Maine (Quoddy Bay and Down East LNG 

Projects), the designated agency, the Maine Department of Environmental Protection, is participating as a cooperating agency. It is reviewing the data in the applications and lending its state-specific knowledge to the analysis that will be presented 

in the environmental impact statements. This cooperative role also facilitates the 

state’s permitting process. 

For the proposed AES Sparrows Point Project in Maryland, the Governor designated the Power Plant Research Program (PPRP) of the Maryland Department of 

Natural Resources as the state’s point of contact. During the pre-filing process, the 

PPRP provided the Commission with multiple rounds of comments that were compiled from other Maryland resource agencies. The PPRP is also assisting Commission staff in analyzing the data filed by AES. For example, issues regarding air 

quality and dredging are being jointly reviewed by PPRP and Commission staff The 

staff is continuing to work closely with these agencies to resolve these concerns. 

For the Broadwater LNG Project, located in New York state waters in Long Island Sound, the pre-filing process lasted more than 12 months and included intensive stakeholder outreach and interagency consultation regarding all aspects of the 

project. The New York Department of Public Service (DPS) was among the state 

agencies consulted during the pre-filing process. The Governor of New York later 

designated the DPS as the state agency that would consult with the Commission 

on safety issues. Although the DPS was not selected by the Governor until one 

month before Broadwater filed its application, it was able to address the state and 

local safety considerations for the project and compile the comments of several New 

York resource agencies due in large part to the consultation that had occurred during the pre-filing process. Similarly, Commission staff was already aware of the 

safety concerns presented by the state and was able to include a response to each 

of the issues in the draft environmental impact statement for the Broadwater 

Project. 

For the Northern Star LNG proposal located in Oregon, the Governor designated 

the Oregon Department of Energy as the state agency that would consult on safety 

issues. The state safety advisory report was filed in the Commission’s record on July 

6, 2006. The commission staff will respond to each issue raised in the state’s report 

in its draft EIS issued in this pending proceeding. 

Question 6. With respect to an LNG facility or a natural gas pipeline, EPAct 2005 

amended Section 19 of the Natural Gas Act to provide for federal court review of 
64

an order or action of a Federal agency (other than the Commission) or a State administrative action acting pursuant to Federal law (other than the Coastal Zone 

Management Act. I understand that at least one pipeline applicant has taken advantage of this review authority. Please provide the committee with information on 

this case and on any other cases in which applicants taken advantage of this review 

authority since the enactment of EPAct 2005. In your opinion, does this review authority significantly enhance the Commission’s ability to site needed energy infrastructure? Does it provide an acceptable balance between state and federal interests? 

Answer. One pipeline, Islander East Pipeline Company, has acted under EPAct 

2005’s revisions to section 19 of the Natural Gas Act. On September 19, 2002, the 

Commission issued to Islander East Pipeline Company a certificate of public convenience and necessity, authorizing the company to construct, own, and operate a 44.8-

mile, 260,000-decatherm pipeline, extending from Northhaven, Connecticut, across 

Long Island Sound, to Brookhaven Long Island, New York. The pipeline would 

begin at an interconnection with the facilities of Algonquin Gas Transmission Company, and provide service to a number of customers, including KeySpan Gas East 

Corporation, the Brooklyn Union Gas Company, AES Endeavor, and Brookhaven 

Energy Limited Partnership. The Commission found that the proposed facilities 

were necessary to provide additional capacity and an additional pipeline link to 

Long Island, which is currently served by only one pipeline. The Commission’s Islander East orders are final, and have been affirmed by the U.S. Court of Appeals 

for the District of Columbia Circuit. 

Prior to construction of the pipeline, Islander East is required to obtain a certification (or waiver thereof) from the State of Connecticut pursuant to section 

401(a)(1) of the Clean Water Act that any discharge resulting from construction and 

operation of the Islander East Project will comply with specified provisions of that 

act. Islander East applied for certification on February 13, 2002. On February 2, 

2004, the Connecticut Department of Environmental Protection issued a decision denying the company’s request for certification. Islander East thereafter appealed the 

decision to Connecticut state court. That action was still pending on August 8, 2005, 

when EPAct 2005 was enacted, amending section 19 of the Natural Gas Act to give 

the U.S. Courts of Appeals original and exclusive jurisdiction over such actions. 

On that date, Islander East filed in the U.S. Court of Appeals for the Second Circuit a petition for review of the Connecticut Department of Environmental Protection’s order. On October 5, 2006, the court ruled that the Connecticut Department 

of Environmental Protection’s action in denying certification was arbitrary and capricious, and remanded the matter to the agency for further review and action within 75 days of issuance of the court’s opinion. On December 19, 2006, the Connecticut 

Department of Environmental Protection issued another order denying the company’s request for certification. Islander East’s appeal of this latest order is pending. 

I believe that the judicial review provisions added by EPAct 2005 provides for efficient judicial review of agency decisions, by giving applicants direct access to Federal appeals courts for review of adverse decisions of state agencies acting under 

Federal authority. We do not yet have a great deal of experience with the ultimate 

effect of these new provisions. However, as evidenced by the circumstances in Islander East, I believe that giving parties access to federal appellate review ensures 

that important gas infrastructure projects receive an appropriate level of judicial 

scrutiny. At the same time, section 19 preserves the authority of states to make key 

decisions. I think this approach strikes the right balance between federal and state 

interests. 

Question 7. In 2003, the Commission adopted a policy statement on consultation 

with Indian tribes in Commission proceedings. The policy statement said that the 

Commission would establish the position of tribal liaison, which would provide a 

point of contact and a resource for tribes in Commission proceedings. Given recent 

efforts to promote tribal development of energy resources, including the Energy Policy Act of 2005, this position would seem to be an important one within the Commission. Is the position of tribal liaison currently filled? How is it working? Could you 

provide, for the record, an update on how the Commission is using its liaison to 

work with tribes on energy matters? 

Answer. The position of tribal liaison is currently filled by an attorney in the Office of the General Counsel with extensive experience in working with Tribes in hydroelectric licensing proceedings. Between the Office of the General Counsel and the 

Commission’s program offices, in most instances the Office of Energy Projects, the 

Commission reaches out to Tribes to ensure that they have a full understanding of 

the Commission’s procedures and of their opportunities to participate in Commission 

proceedings, to ascertain their interests in particular proceedings, to seek their 

views, and to ensure that Commission staff has the information needed to seek out 
65

tribal concerns and to interact with Tribes in an appropriate, respectful manner. 

The tribal liaison is available to serve as an initial point of contact for the Tribes, 

to be a resource to answer questions that Tribes or staff may have, and to put Tribal 

representatives in touch with other members of Commission staff who can best answer their questions. In many proceedings, at the Tribe’s request, Commission staff 

and the Tribes meet to exchange views, concerns, and information. The position of 

tribal liaison is a relatively new position at the Commission, but it provides a valuable resource to Tribes. 

RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR DOMENICI

Question 1. We gave FERC a lot to do in the Energy Policy Act of 2005. Please 

briefly outline the steps the Commission has already taken and what, in your opinion, are the most important things remaining to be done. 

Answer. The Commission has issued 14 final rules, 1 proposed rule, and 7 reports, 

and has entered into 2 memoranda of understanding, pursuant to EPAct 2005. It 

has met all statutory deadlines for issuing items for which Congress gave it sole or 

lead authority: The following is a list of our major actions under EPAct 2005. The 

Commission has, pursuant to EPAct 2005, adopted:

1. regulations on pre-filing procedures for review of LNG terminals and other 

natural gas facilities under the NGA; 

2. regulations to implement repeal of the Public Utility Holding Company Act 

of 1935 and enactment of the Public Utility Holding Company Act of 2005; 

3. regulations on mergers and other corporate transactions subject to FPA 

section 203; 

4. policy statement governing how the Commission would use its EPAct 2005 

civil penalty authority; 

5. rules governing how the Commission would impose civil penalties through 

administrative litigation when settlements are not reached; 

6. regulations prohibiting market manipulation in connection with jurisdictional electric energy and natural gas markets under the FPA and NGA; 

7. regulations governing criteria for qualifying small power production and cogeneration facilities under PURPA; 

8. rules under the FPA concerning certification of the Electric Reliability Organization and procedures for establishment, approval, and enforcement of electric reliability standards for the bulk power transmission system; 

9. regulations for pricing of natural gas storage facilities under the NGA; 

10. rules under the FPA to promote electric transmission investment through 

pricing reform; 

11. regulations under the FPA to provide load-serving entities with long-term 

firm transmission rights in organized electricity markets; 

12. regulations on financial accounting, reporting and record retention requirements under PUHCA 2005; 

13. regulations on coordinating processing of federal authorizations for applications under sections 3 and 7 of the NGA and maintaining a complete consolidated record; 

14. regulations under PURPA governing electric utilities’ obligation to purchase electric energy from qualifying small power production and cogeneration 

facilities; 

15. regulations under the FPA for filing applications for permits to site transmission facilities in national interest electric transmission corridors; 

16. rules under the FPA establishing mandatory reliability standards for the 

bulk power system; 

17. delegation agreements authorizing eight regional entities to enforce mandatory reliability standards approved by the Commission; 

18. notice of proposed rulemaking on transparency requirements in wholesale 

natural gas markets; 

19. memorandum of understanding between FERC and the CFTC regarding 

information sharing and treatment of proprietary trading and other information; 

20. memorandum of understanding among federal agencies to coordinate applicable federal authorizations and related environmental reviews for siting of 

transmission facilities (DOE, DOD, USDA, DOI, DOC, FERC, EPA, CEQ and 

ACHP) 

21. reports to Congress on Alaska Natural Gas Pipeline (3 reports); 

22. report to Congress on any technical amendments needed to carry out 

PUHCA 2005; 

23. report on demand response and advanced metering; 
66

24. report to Congress on California energy crisis refunds; 

25. convening of FERC-state joint boards/report to Congress on security-constrained economic dispatch; 

26. joint DOE-FERC report to Congress on transmission monitoring for transmission owners and operators in the Eastern and Western interconnections; and 

27. joint report to Congress on competition in wholesale and retail markets 

for electric energy (joint report by DOJ, FERC, FTC, DOE and USDA).

In addition to the above, the Commission has used the new civil penalty authority 

under the FPA and NGA in seven cases. 

In my view, the most important matters remaining to be done as a result of 

EPAct 2005 are: (1) continued improvement and establishment of mandatory reliability rules including rules for cyber security, and vigilant enforcement of reliability rules; and (2) ongoing vigilant oversight of wholesale natural gas and electric 

markets and maintenance of a strong enforcement program to ensure compliance 

with the statutes administered by the Commission, with appropriate and fair use 

of the Commission’s new civil penalty authority. Further, with respect to implementation of all of the above EPAct-related matters and all of the new statutory provisions for which the Commission is responsible, we will continue our diligent, careful 

work to see that the letter and spirit of the statutory provisions and rules are fulfilled in individual cases. 

Commission staff has recognized more resources are necessary for reliability and 

reliability-related enforcement. As a result, I will soon request to the relevant appropriations committees that the Commission’s FY08 appropriations be funded at $9 

million above the President’s FY08 budget request. As we have gained experience 

implementing EPAct section 215, it has become apparent that our projected resource 

requirements for implementing the reliability program were underestimated. Increased Commission staff presence is required in standards setting, cyber security, 

and enforcement. As you know, the Commission is a self-supporting agency and 

would recover the additional appropriations through fees, as it does all of its costs, 

and will continue to operate at no net cost to the taxpayer. 

Question 2a. EPAct directed FERC to ensure the reliability and security of the 

nation’s bulk-power system. Pursuant to the Energy bill, a single Electric Reliability 

Organization—the ‘‘ERO’’—has the authority to establish and enforce mandatory reliability standards. FERC has already designated the North American Electric Reliability Corporation (NERC) as the ERO. In March, FERC approved 83 reliability 

standards and just last month, FERC approved NERC’s pro forma Delegation 

Agreement, to allow regional entities the ability to enforce mandatory reliability 

standards. 

Is the transition from a system of voluntary compliance to this new mandatory 

regime nearly complete? 

Answer. Yes, to a large degree. As you have outlined, the three major procedural 

steps towards a mandatory reliability regime have been completed thanks to the 

vigorous efforts of Commissioners, Commission staff, NERC, the regional entities, 

and industry. However, there is much work to be done. For instance, of the 83 

standards that the Commission approved, 56 require improvement and additional 

standards need to be put in place (examples include cybersecurity and physical security standards). The regional entities are also preparing to begin enforcing reliability 

standards by increasing staffing, completing compliance registration lists, conducting outreach programs to the industry and other steps. 

Question 2b. Do you have confidence that this new reliability system will prevent 

rolling blackouts this summer? 

Answer. Last summer represented the greatest challenge to the reliability of the 

interstate power grid since the August 2003 blackout. Although there were failures 

of the local distribution system, the interstate grid withstood the challenge. No statute or regulation can guarantee that there will never be another blackout. However, 

the certification of an Electric Reliability Organization, the establishment of mandatory and enforceable reliability standards, and the approval of the regional delegation agreements have laid the foundation for a more reliable bulk power system. We 

are now better prepared to assure reliability of the interstate power grid, and can 

now take enforcement action if standards are violated. These activities have already 

started to generate benefits by heightening awareness in the industry and prompting preemptive actions. The new reliability system is based on mandatory reliability 

standards that are backed by penalties for noncompliance and this system has 

caused entities subject to the standards to carefully scrutinize their own adherence. 

In some cases this has led them to self-report violations in order to seek approval 

for mitigation plans that will bring them into compliance with the standards. Such 

actions can and will steadily improve the reliability of the bulk power system. 
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7See Regulations for Filing Applications for Permits to Site Interstate Electric Transmission 

Facilities, Order No. 689, 71 Fed. Reg. 69,440 (Dec. 1, 2006), FERC Stats. & Regs. Paragraph 

31,234 (2006). 

Question 2c. What is your plan for FERC interaction with the regional entities? 

Answer. We are working with the regional entities on a number of fronts. For instance, I have already directed Commission staff to engage in the reliability standards development process, both at the ERO and the regional entity level to help improve the quality of the standards as well as their timeliness through open communication with the Commission. In addition to our involvement with standards development, Commission staff will participate in the regional planning processes which 

are intended to identify reliability problems and set mitigation plans in place to address them before they even materialize. In order to assist the regions with enforcement matters, I have authorized Commission staff to join with the regional entities 

in a representative sampling of regular compliance audits in each of the regions 

shortly after they begin. In addition, Commission staff will work with the regional 

entities and ERO to investigate selected incidents on the bulk power system to ensure that we learn from any such incidents. 

Question 3a. I don’t think anyone would argue against the need for more transmission infrastructure in this country. One of the biggest problems with siting the 

necessary infrastructure is local opposition to new interstate transmission lines. In 

EPAct, we provided FERC with ‘‘back-stop’’ siting authority in areas the Energy Department has designated as ‘‘National Interest Electric Transmission Corridors.’’ 

Last week, DOE released draft corridor designations and I understand that FERC 

has already issued a siting rule. However, FERC’s new authority does not become 

operative until states have had a full year to review and act upon the proposed 

transmission project. 

Do you believe that the majority of these projects will continue to be sited by the 

states? 

Answer. Yes. In my view, states retain primary jurisdiction to site transmission 

facilities, and the Commission’s role is secondary and supplemental. I believe most 

applicants will make every effort to work with states to obtain siting authority. I 

anticipate that only in rare cases will an applicant file with the Commission. Section 

1221 of EPAct 2005 (new FPA section 216) provides for the federal siting of electric 

transmission facilities under circumstances where the U.S. Department of Energy 

has identified transmission constraints or congestion and designated the area as a 

national interest electric transmission corridor and where: a state commission either 

has no authority to site or cannot consider interstate benefits, the applicant does 

not serve end-users in the state and thus does not qualify for a state permit, a state 

commission conditioned approval such that construction will not reduce congestion 

or is not economically feasible, or a state commission has withheld approval for 

more than one year after the filing of an application seeking approval pursuant to 

applicable state law. The Commission implemented new regulations to establish filing requirements and procedures for entities seeking to construct electric transmission facilities under these circumstances.7

Question 3b. In cases where the state does not act, what prerequisites do you expect FERC to require before stepping in? 

Answer. Commission staff will encourage a prospective applicant to obtain siting 

authority from states whenever possible. The Commission has offered both its technical expertise as well as the services of its Office of Dispute Resolution to assist 

states and applicants to resolve issues and to encourage timely state siting decisions. Should Commission review, however, become necessary, our regulations require a prospective applicant to meet with Commission staff to demonstrate whether 

the proposed project is eligible for an electric transmission construction permit and 

that the applicant has the resources available to initiate a pre-filing process. Then, 

only after an extensive pre-filing process during which Commission staff works with 

the applicant to resolve regional, state, and local issues, may an applicant file an 

application with the Commission. During this pre-filing process, Commission staff 

also will consult with affected stakeholders, including state agencies. 

Once the pre-filing process is complete and the application has been filed, there 

are rigorous requirements that must be met before an application can be approved. 

In order to meet NEPA requirements, Commission staff, as lead agency, will prepare and issue of draft and final environmental impact statement during the application phase. Also, as lead agency, the Commission must coordinate the other necessary federal authorizations. During the application phase comment periods will be 

established for the states and affected landowners after the issuance of a public notice of the application, and the issuance of the draft environmental impact state-
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ment. After all these pre-requisites are satisfied, the Commission must make the 

statutory findings in section 216(b) before it can issue a construction permit. 

Question 4a. There have been questions in the industry as to whether competition 

is the ‘‘right’’ policy for our wholesale electric markets. Just this past year, FERC 

has conducted two technical conferences on the subject of competition. 

Has our national policy of competition in wholesale electricity markets resulted 

in higher rates for consumers? 

Answer. I do not believe that our overall national policy of increasing competition, 

and thereby encouraging innovation and increasing choices for customers, has raised 

rates. Competition is national policy in wholesale power markets, but the Commission does not rely solely on competition to assure just and reasonable prices. We rely 

on a combination of competition and regulation. In some cases, wholesale competition has not worked as envisioned. For example, in some areas, such as California, 

wholesale markets were not well designed and those flaws harmed consumers in 

California and the West. The proper response is to change the mixture between our 

reliance on competition and regulation to assure more competitive markets and 

more effective regulation. We believe the new regulatory tools Congress gave us in 

EPAct 2005 can help improve competition in wholesale power markets. In this regard, the Commission has taken a number of steps over the years to strengthen 

markets and EPAct 2005 gave the Commission important new authority to police 

market manipulation and assess civil penalties for misconduct. It is important to 

remember that national policy has evolved over the last 30 years to support competition for very important reasons. Traditional regulation that relies solely on the 

monopoly provision of electric service can discourage innovation, impede entry by 

more efficient competitors, and increase risks for consumers. The three major pieces 

of energy legislation enacted over the past thirty years (Public Utility Regulatory 

Policies Act of 1978, Energy Policy Act of 1992 and Energy Policy Act of 2005) were 

all designed to counteract these flaws. 

Although competition is national policy, I respect the decisions of states that have 

retained the regulated model for serving retail customers and believe that national 

efforts to increase wholesale competition are fully compatible with varying state 

choices regarding competition or regulation. Whatever the state choice, greater 

wholesale competition can provide better opportunities for load serving entities to 

provide reliable and economic service to their retail customers. 

One of competition’s clear benefits to customers is the shift of risk away from consumers. As an example, many generating units were built in recent years outside 

of cost-based rates and, particularly in the case of natural gas fired generation, the 

investors in those units have suffered the risks of poor investments. In some instances, these risks have led to bankruptcies. In these instances, it is the investor 

who bore the losses, not the consumer. That stands in stark contrast with the nuclear cost overruns of the 1970s and 1980s, which were largely borne by consumers 

and recovered through regulated rates. Other benefits of competition include improvements in nuclear plant operation and construction of more efficient generating 

units. I expect that competition and innovation will only increase in the future, as 

the Nation demands greater reliance on demand side resources and renewable resources. Vigorous wholesale competition is well suited to facilitate the development 

of these resources. 

Question 4b. Are there administrative steps the Commission could take to improve 

competition in wholesale markets? 

Answer. Yes, and we have adopted many reforms in the past two years to 

strengthen competition and protect consumers. We adopted Order No. 890, which 

will ensure that available grid capacity is measured in a fair and transparent manner and that customers have a seat at the table in the transmission planning process. We adopted Order No. 681, which will ensure that customers in organized markets have long-term transmission rights to support their investments in new resources. We adopted reforms to increase customer access to renewable sources of energy. Order No. 890 created a ‘‘conditional firm’’ service that is important to wind 

resources, and it also reformed energy imbalance charges to ensure that wind and 

other intermittent resources are treated fairly. More recently, we approved California’s proposal to facilitate renewable development by reforming our interconnection 

pricing policies. 

We continue to work to strengthen wholesale power markets. In 2006, we issued 

a proposed rulemaking to improve our market-based rate program. I expect to adopt 

a final rule soon. We also have commenced a generic review of competition in wholesale power markets, to identify additional reforms to ensure that these markets continue to benefit consumers. Our last conference focused on organized markets, with 

the main issues being demand response, long-term contracts and the responsiveness 
69

of RTOs and ISOs to customers and other stakeholders. The Commission is considering the suggestions made at the conferences, with the goal of taking action soon. 

Question 4c. Do you believe further Congressional legislation is needed in this 

area? 

Answer. I do not believe further Congressional legislation is needed at this time. 

Two years ago, Congress enacted the Energy Policy Act of 2005. As I stated in my 

written testimony, this law represents the most important change in the laws the 

Commission administers since the New Deal, and the largest single grant of regulatory power to the agency in 70 years. The application of those laws in future cases, 

and the interpretation of those laws by the courts, may identify areas where additional legislation may be needed. 

Question 5a. EPAct provided the Commission with civil penalty authority and FERC has already assessed civil penalties totaling $22.5 million. In your testimony, 

you state that the newest FERC mission is now enforcement. However, you indicate 

that additional enforcement powers are needed. Please elaborate on what additional 

enforcement tools FERC needs and why. 

Answer. EPAct provided the Commission with the enforcement tools it needed, 

greatly expanding our civil penalty authority and providing broad anti-manipulation 

authority. With these tools our enforcement mission has certainly been enhanced 

immensely and I believe the Commission has sufficient enforcement powers. 

Question 6a. As you know, we’ve seen a great deal of interest in developing ocean 

energy projects. However, we seem to have competing federal jurisdiction for licensing these projects—FERC for anything within 3 miles from shore and the Minerals 

Management Service for those projects located on the Outer Continental Shelf. It 

is my understanding that FERC is currently negotiating with the MMS on a Memorandum of Understanding to govern this jurisdictional issue. 

What is the status of those negotiations? 

Answer. The Commission and the Minerals Management Service (MMS) staffs are 

currently developing a memorandum of understanding (MOU) with the goal of 

reaching agreement on a process that will allow both agencies to develop an efficient 

and effective program for promoting and regulating the development of hydropower 

in offshore areas. Both agencies share this goal, and the discussions have been productive. The current target date for execution of the MOU is early summer 2007. 

I note that we expect that the majority of new technology projects will be located 

not on the Outer Continental Shelf (OCS), but in state waters. Of the 24 preliminary permit applications for ocean energy projects that are currently pending at the 

Commission, only four would be located on the OCS. This distribution of proposals 

reflects the fact that the cumulative costs of development, which include the costs 

associated with the transmission cable needed to bring project power onshore, make 

it advantageous to locate projects nearer to the shore. For those projects located 

wholly or partially on the OCS, the Commission will actively work with the Minerals Management Service under the terms of the MOU. 

Question 6b. How many ocean projects has FERC worked on to date? 

Answer. As of May 15, 2007, the Commission has issued 35 preliminary permits 

for ocean and coastal hydropower projects, and, as I just mentioned, has 24 preliminary permit applications pending. Commission staff is processing our first license 

application for a wave energy hydropower project, the Makah Bay Offshore Wave 

Energy Project (Finavera Renewables). This project, proposed for Makah Bay in 

Clallam County, Washington, part of which would be located on lands of the Makah 

Nation Indian Reservation, would consist of four buoys moored 3.2 nautical miles 

offshore in the Olympic Coast National Marine Sanctuary. Together, the buoys 

would generate up to 1 megawatt (MW), with an average of about 200 kilowatts 

(kW). The application was received on November 8, 2006. Commission staff expects 

to issue its environmental assessment of the project within the next few weeks. 

Commission staff is also working closely with stakeholders for two projects for 

which license applications are being prepared: Verdant Power, Inc. is proposing the 

Roosevelt Island Tidal Energy Project to be located in the East River in New York, 

New York; and Reedsport OPT Wave Park LLC, for the proposed Reedsport Project 

in Douglas County, Oregon. 

Question 6c. Is FERC proceeding pursuant to its traditional hydropower licensing 

authority, and if so, is that appropriate or is there a better way to approach the 

licensing issue? 

Answer. In general, the Commission will draw heavily from its experience obtained from its existing hydropower licensing procedures. These procedures have 

worked well over time and are sufficiently flexible to address the licensing of 

projects using the new technologies. Where appropriate, the Commission will investigate making improvements to the current process to the extent consistent with existing law. Our December 2006 technical conference on these new technology 
70

8 Verdant Power, LLC, 111 FERC Paragraph 61,024 (2005). 

projects and the comments we received subsequently, along with comments received 

on the Commission’s March 2007 Notice of Inquiry regarding our preliminary permit 

program, will be used to adapt procedures to the needs of new technology projects. 

In fact, the Commission has already instituted, on an interim basis, a strict scrutiny 

approach to processing preliminary permits as described in response to Senator Wyden’s question 10. In addition, the Commission has determined that the testing of 

experimental hydropower projects can proceed without a Commission license, so 

long as criteria set forth in Verdant Power are met.8 This is described in detail in 

response to Senator Wyden’s question 11. We recognize that these technologies are 

new and there is a need for demonstrations and pilot projects. We are exploring how 

to best accommodate this need. 

The Commission is uniquely positioned under Part 1 of the Federal Power Act 

(FPA) and its regulations to give equal consideration to developmental and non-developmental resources and to assure that any project licensed will be best adapted 

to a comprehensive plan for development of the water resource in the public interest. Our licensing process is transparent, provides timely review of projects, and affords applicants, agencies, Native American tribes, non-governmental organizations, 

and members of the public numerous opportunities to effectively participate and 

represent their interests. 

Question 7a. Some in Congress want to require all public utilities and Regional 

Transmission Organizations subject to FERC’s jurisdiction, to post day-ahead and 

real-time energy prices using a standard format that is readily accessible by the 

general public. 

While this sounds reasonable, wouldn’t this run the risk of revealing confidential 

information that could facilitate collusion? 

Answer. As a general matter, price transparency facilitates transactions in competitive markets by making it easier and more efficient for customers to make reasoned market decisions and by increasing confidence that the markets are functioning fairly. For example, organized electricity markets currently publish market 

clearing prices close to real-time to allow customers to make efficient short-term 

supply decisions. These markets do not, however, publish actual bids, unit costs or 

bilateral trades in real-time. This is so because such information could facilitate collusion and harm customers. Indeed, section 1281 of EPAct 2005 (new FPA section 

220) requires the Commission to ensure that consumers and competitive markets 

are protected from the adverse effects of potential collusion or other anticompetitive 

behaviors that can be facilitated by untimely public disclosure of transaction-specific 

information. In addition, price information related to individual transactions in realtime is typically considered commercially sensitive. Requiring sellers to post their 

bid or cost data could put them at a competitive disadvantage or could harm customers by revealing the price at which they are willing to transact. After the fact, 

however, all jurisdictional transaction prices are reported to the Commission 

through Electric Quarterly Reports, which facilitates long-term investment decisions 

as well as the ability of the Commission and others to monitor the market for manipulation. In addition, most organized markets release bid data after a several 

month delay. In conclusion, although I support transparency of price information as 

a general matter, the Commission needs to be careful in deciding which information 

should be posted and in what time frame. To the extent legislation is considered, 

it should provide the Commission discretion to address these concerns. 

Question 7b. Also, how would this work in the bilateral markets of the Southeast 

or West? 

Answer. In the Southeast and the West (outside of California), there are no bidbased organized electricity markets that produce a market-clearing price. Rather, 

market participants transact bilaterally at agreed upon prices or at tariff rates. 

While there are services in bilateral markets that aggregate trades and publish average prices, there currently is no requirement to publish in real-time the actual 

transactions agreed to by sellers and customers. The posting of energy prices in 

real-time could present some of the same concerns expressed in response to the previous question, i.e., it could implicate the confidentiality of the counterparties involved in such transactions. Moreover, revealing prices in real-time could affect the 

ability of load serving entities to negotiate the best deal possible for their customers. 

By aggregating price information or delaying its release, however, these concerns 

can be addressed. For example, requiring the posting of average costs, as the Commission did recently in Order No. 890 with respect to redispatch costs, the Commission can provide access to cost or price information without harming competition or 

revealing otherwise competitively sensitive information. In addition, as indicated, 
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the Electric Quarterly Reports provide this information on a delayed basis for all 

regions of the country, including the Southeast and West. 

Question 7c. What is FERC currently doing and what plans for the future do you 

have to encourage better transparency? 

Answer. The Commission is acting to encourage better transparency in both 

power and gas markets. Pursuant to the transparency provisions of EPAct 2005 section 316 (new NGA section 23), the Commission recently proposed to require that 

intrastate pipelines post daily the capacities of, and volumes flowing through, their 

major receipt and delivery points and to require buyers and sellers of more than 

a de minimis volume of natural gas to report annual numbers and volumes of relevant transactions. This proposal will improve the transparency of gas markets, 

both the size of the physical gas market and flows across the gas infrastructure. 

The Commission continues to address transparency issues in wholesale electric 

markets. The Commission already collects basic information about all jurisdictional 

electric transactions in the Electric Quarterly Reports and makes this information 

available to the public. As noted above, RTOs and ISOs report a wide variety of 

market-related information, including both day-ahead and real-time prices, in near 

real-time. Recently, the Commission acted to improve the transparency of electric 

transmission services. In its final rule reforming the Open Access Transmission Tariff, the Commission increased the transparency of a transmission provider’s transmission planning, the transparency of its calculations of Available Transfer Capability, and the transparency of its business rules and practices. Finally, the Commission now publishes a wide variety of information about electric markets on the market oversight portion of its website (http://www.ferc.gov/market-oversight/marketoversight.asp). 

Going forward, the Commission is considering transparency in wholesale electric 

markets in the broader context of competition in those markets. In the first of a series of public conferences on the state of competition in wholesale power markets, 

held February 27, 2007, the Commission and panelists considered price transparency, among other topics. When the series of conferences is complete, the Commission will take appropriate steps on a variety of issues related to competition, including transparency. The Commission and a few traditional utilities are now discussing ways in which companies outside RTOs and ISOs might provide the Commission with important market information voluntarily, and the Commission could 

publish some of that information. Finally, within RTOs and ISOs, the Commission 

is currently reviewing the role of Market Monitoring Units, partly to ensure market 

transparency. 

RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR WYDEN

Question 1a. There are two preliminary LNG applications pending before and at 

least one more application expected soon. It is my understanding that Federal Energy Regulatory Commission (FERC) staff have engaged state agencies and sought 

Oregon’s comments, but it is not clear to what extent, if any, those comments will 

be integrated into the final site permit. For example, the State has two specific state 

standards that do not have a clear counterpart in the FERC permitting and licensing process—our carbon dioxide offset standard and our facility retirement standard. 

How will FERC address these two State siting standards or if they will disregard 

them in the final licenses? 

Answer. Although applicants for authority to construct and operate LNG terminal 

facilities under section 3 of the Natural Gas Act are not required to meet state 

siting requirements as such, the Commission’s staff actively seeks input from interested state agencies. The Commission does not have a specific carbon dioxide offset 

standard, but I recognize that the issue has been raised during the scoping process 

for the LNG projects in Oregon. I assure you that Commission staff will address all 

project-related effects to air quality, including emission of carbon dioxide, in its draft 

Environmental Impact Statement (EIS). Emissions from the facilities and the 

berthed tankers will be compared to state and federal standards and the Commission will determine whether mitigation of the impacts is necessary. The draft EIS 

will be open for public comment for 45 days, and the Commission will hold community meetings to solicit public comments. The Commission will consider those comments and address them in any final EIS. 

With respect to facility retirement issues, pipeline facilities subject to the Commission’s jurisdiction cannot be abandoned unless the Commission first finds, pursuant to section 7(b) of the Natural Gas Act, that the present or future public convenience and necessity permit such abandonment. A review and consideration of environmental impacts is a component of that determination. While no analogous requirement exists in section 3 of the Natural Gas Act with regard to LNG facilities, 
72

the courts have determined that the Commission’s authority under this section is 

plenary and elastic, and is interpreted as including any authority that exists under 

section 7. When the Commission authorizes an LNG terminal it reserves the right 

to take any action necessary to protect life, health, property, or the environment. 

That extends to facility decommissioning. Consequently, at such time as an LNG 

terminal operator seeks to cease operating its facilities, the Commission would determine what measures would be necessary to safely remove the facility from service 

in an environmentally sound manner. 

Question 1b. How does FERC intend to address other State agency comments and 

what assurance will State agencies receive that their comments will actually be addressed and when will they receive it? 

Answer. After the May 10 hearing, I directed staff to make sure that comments 

from Oregon state and local agencies were being considered. I was assured that they 

are, as is standard Commission practice. In the case of the Bradwood Landing LNG 

Project, the Commission received 13 letters from various Oregon state agencies during the pre-filing process, which lasted from March 2005 to June 2006. This included letters from the Oregon Department of Energy, Oregon Department of Fish 

and Wildlife, Oregon Department of Transportation, Oregon Department of Land 

Conservation and Development, and the Oregon State Historic Preservation Office. 

During the pre-filing process, Northern Star filed draft environmental resource reports, and Oregon state agencies filed comments on those draft reports. Commission 

staff then issued data requests to Northern Star to address those state agency comments. Northern Star’s application, filed June 5, 2006, included changes in the resource reports that reflected the comments from Oregon state agencies. Even after 

the application was filed, the Commission received nine comments from Oregon 

state agencies, and we issued six additional data requests to fill data gaps identified 

by those agencies. All of the information collected comprises the record that will 

form the basis of Commission staff’s draft EIS. 

The Jordan Cove LNG project and associated 250 miles of pipeline proposed by 

Pacific Connector pipeline are currently in the pre-filing process and will be considered together in a single EIS. Since the start of the pre-filing review in May 2006, 

the Commission has received 11 letters from Oregon state agencies. The Commission staff has issued 10 data requests for these projects asking the project sponsors 

to address numerous issues, including the comments from Oregon state agencies. 

The Commission staff is continuing to work with federal, state, and local agencies 

to identify and resolve issues prior to the filing of applications with the Commission. 

Because all of the comments and responses are part of the Commission’s public 

record, stakeholders have continuous access to the material in these cases that will 

form the basis of our EIS. 

After the project sponsors file their applications, Oregon state agencies will have 

the opportunity to file interventions to become formal parties to the proceedings 

which, among other rights and responsibilities, will give those parties standing on 

which to ask for rehearing of any Commission decision. The next milestone will be 

the issuance of a draft EIS after the staff determines that it has sufficient data to 

proceed. In our preparation of the draft EIS, the staff reviews and analyzes all comments received, and must consider the comments collectively and analyze their impact on the full scope of human environment in the draft EIS, rather than respond 

to individual comments as they are received. 

The draft EIS will be issued for public comment for a minimum of 45 days and 

community meetings will be held in the project areas to solicit public comment. 

Comments will be accepted both in writing and at public comment meetings. In this 

way, state and local agencies will have opportunity to let the Commission know 

whether their concerns have been adequately addressed. The staff must reply to 

each specific comment made about the draft EIS, and publish those responses in a 

final EIS. That EIS and comment responses become part of the record the Commission uses to formulate its decision. 

Question 2a. The Oregon fish and wildlife agency has submitted numerous comments to FERC related to protection of salmon habitat and salmon fisheries. Obviously there will be impacts not only from the construction of the terminals, but also 

from related dredging for navigation, and from construction of related pipelines. 

How will FERC ensure that salmon habitat and salmon fisheries are not injured 

during terminal construction, dredging and laying the pipelines, including the proposed section across/under the Columbia River and what legal or regulatory standards will apply? 

Answer. The Commission’s regulations at 18 CFR 380.12 outline the data applicants must provide in their environmental resource reports to assist the Commission in meeting its obligations under the National Environmental Policy Act 

(NEPA). Resource Report 3 must address ‘‘Fish, Wildlife, and Vegetation,’’ including 
73

fisheries and associated habitat, and any federally-listed essential fish habitat 

(EFH). Part 380.13 of the regulations outline requirements to comply with the Endangered Species Act (ESA). 

The Commission requires that applicants consult with state and federal resource 

agencies and conduct surveys necessary to identify federally-listed threatened and 

endangered species and state species of concern that may be affected by the proposed project. In the case of the Bradwood Landing LNG Project, many of the salmon species in the Columbia River and its tributaries crossed by the associated sendout pipeline are federally-listed as either threatened or endangered. 

The draft EIS will discuss potential project impacts on salmon and their habitat, 

and proposed mitigation measures such as screening, seasonal construction restrictions, and water quality monitoring. Both Northern Star and Jordan Cove have 

agreed to adhere to the habitat mitigation policy developed by the Oregon Department of Fish and Wildlife (ODFW). The draft EIS will also discuss the status of 

compliance with the ESA and the Magnuson-Stevens Fishery Conservation and 

Management Act (MSA). 

The existing regulatory framework would ensure the protection of salmon habitat 

and fisheries. Under section 7(a)(2) of the ESA, a federal action agency that permits, 

licenses, funds, or otherwise authorizes activities must consult with the U.S. Department of the Interior Fish and Wildlife Service (FWS) and the U.S. Department 

of Commerce National Oceanic and Atmospheric Administration National Marine 

Fisheries Service (NMFS), as appropriate, to ensure that its actions will not jeopardize the continued existence of any listed species or destroy or adversely modify 

critical habitat. 

To meet the Commission’s obligations to consult under the ESA, Commission staff 

has prepared a Biological Assessment (BA) for the Bradwood Landing project and 

is currently gathering the necessary data to complete a BA for the Jordan Cove 

project. After completing their review of the BA, the FWS and NMFS may provide 

a Biological Opinion (BO) to the Commission. The BO will likely include Terms and 

Conditions, which will be designed to further protect listed species. 

The MSA requires the identification of EFH for federally managed fishery species 

and the implementation of measures to conserve and enhance this habitat. Federal 

agencies must consult with the NMFS on activities that may adversely affect EFH 

(MSA section 305(b)(2)). 

There are situations where designated EFH overlaps with the habitat of species 

listed as threatened or endangered under the ESA. Thus, a proposed federal action 

could affect both a listed species and its designated critical habitat and adversely 

affect EFH, necessitating consultation under both section 7 of the ESA and section 

305(b)(2) of the MSA. Commission staff is integrating these consultations in the review processes for both the Bradwood Landing and Jordan Cove projects. 

Commission staff included an EFH Assessment with the BA for the Bradwood 

Landing LNG Project. Jordan Cove is still gathering its EFH data for Commission 

staff review, and the review of other relevant federal and state resource agencies. 

Once NMFS has reviewed the EFH Assessment and analyzed possible adverse effects to EFH resulting from the proposed action, NMFS must develop EFH conservation recommendations. These recommendations may include measures to 

avoid, minimize, mitigate, or otherwise offset adverse effects on EFH. While the 

EFH conservation recommendations for the projects have not yet been developed, 

the Commission would use the recommendations in evaluating ways of reducing impacts to fisheries. 

Commission staff’s BA and EFH Assessment considered the potential impacts on 

aquatic resources of LNG marine traffic along the waterway, terminal construction 

(including dredging for the turning basins, and pipeline construction). Commission 

staff required that both Northern Star and Jordan Cove conduct sampling of the 

areas to be dredged, analyze the content of dredge material, run models for sediment flow as a result of dredging, and file dredge material placement plans so that 

Commission staff can evaluate potential impacts on aquatic species. The sampling 

designs and results were independently reviewed by scientists working for the U.S. 

Army Corps of Engineers, FWS, and NMFS. 

As proposed, the Bradwood Landing Pipeline is to be installed under the Columbia River using a horizontal directional drill (HDD). The HDD should avoid impacts 

on the river and salmon habitat. However, in the case of a loss of drilling fluids 

or HDD failure, both the BA and draft EIS discuss potential impacts on salmon and 

other aquatic species from an accidental release of drilling mud into the river, and 

offer contingencies that would be implemented to mitigate impacts in such situations. 

Question 2b. To what extent will FERC rely upon mitigation plans and activities 

versus limitations or restrictions on project-related construction activities in order 
74

to protect fisheries and habitat? And, what will FERC do to ensure the adequacy 

of mitigation plans and their long-term implementation over the life of the projects? 

Answer. Commission staff will evaluate whether the mitigation proposed by the 

applicants is sufficient to protect fisheries and habitat. If the proposed mitigation 

is insufficient, the Commission may impose additional environmental measures, possibly including restrictions on construction activity. If the consultation on the appropriate mitigation is not timely completed, Commission staff will often require the 

applicant to complete consultations and submit plans or studies prior to the 

issuance of a final EIS so that there is an opportunity for public review. 

If the projects are approved, the Commission staff will review each step of the design and construction process, with certain written approvals needed before the applicant is allowed to progress to the next phase of construction or place any facility 

in operation. After a project is authorized, Commission staff will perform regularly 

scheduled inspections during construction. Commission staff will continue to conduct 

regular inspections to ensure that the right-of-way has been properly restored. 

After the LNG facility is allowed to be placed into service, Commission staff will 

conduct biennial inspections to ensure safety standards are met. In addition, certain 

environmental conditions may require long-term monitoring and reporting to ensure 

compliance with conditions. Typical environmental conditions include monitoring to 

ensure that disturbed wetlands are restored, that water quality standards are maintained, and that noise levels are consistent with required standards. 

Question 3a. LNG projects, especially the pipeline segments of these projects, impact many communities and local governments. While pipeline transmission siting 

has been a longstanding FERC responsibility, these new pipelines would not be 

built if it were not for the development of the proposed LNG terminals. 

Please explain what steps FERC is taking to ensure that local governments are 

consulted with regard to pipeline routing, construction impacts, and safety related 

to these projects. 

Answer. Our pre-filing regulations have requirements for applicants to communicate with stakeholders, including local governments. Our Notice of Pre-Filing and 

our Notice of Intent to Prepare an Environmental Impact Statement (NOI) are sent 

to all county governments and local communities in the vicinity of a proposed LNG 

terminal and along any proposed pipeline route. In the case of the Bradwood Landing LNG Project, that included Clatsop and Columbia Counties, Oregon, and the 

communities of Warrenton, Astoria, Clatskanie, and St. Helens; Pacific, 

Wahkiakum, and Cowlitz Counties, Washington, and the communities of Ilwaco, 

Cathlamet, Kelso, Longview, and Kalama. In the case of the Jordan Cove LNG 

Project, the NOI was sent to Coos, Douglas, Jackson, Josephine, and Klamath Counties, Oregon, and the communities of North Bend, Coos Bay, Charleston, Coquille, 

Myrtle Point, Powers, Myrtle Creek, Roseburg, Riddle, Canyonville, Elkton, Glendale, Grants Pass, Rogue River, Medford, Jacksonville, Phoenix, Talent, Ashland, 

Shady Cove, Butte Falls, Eagle Point, Central Point, Klamath Falls, Merrill, Malin, 

and Bonanza. 

In response to the NOI for Bradwood Landing, the Commission received comments from the City of Astoria, the City of Clatskanie, the City of St. Helens, 

Clatsop County, Wahkiakum County, and Cowlitz County. For the Jordan Cove 

project, the cities of Coos Bay, North Bend, Winston, and Canyonville, Oregon filed 

comments. 

For the Bradwood Landing LNG Project, Commission staff attended public open 

houses in Knappa, Oregon and Longview, Washington in May and September 2005, 

and we held public meetings in Knappa, Oregon on September 29, 2005, and in 

Cathlamet, Washington on October 26, 2005. The issues you mentioned were discussed at these meetings. In addition, during the pre-filing process, Commission 

staff participated in eight interagency meetings for the Bradwood Landing Project 

that included county and local government representatives. For the Jordan Cove 

LNG Project, Commission staff attended public open houses in Coos Bay, Canyonville, Shady Cove, and Klamath Falls in June 2006, and we held public meetings 

in Coos Bay, Roseburg, Medford, and Klamath Falls in October 2006, and in North 

Bend, Roseburg, and Medford in January 2007. In addition, Commission staff has 

also participated in five interagency meetings for the Jordan Cove Project that included county and local government representatives. Representatives of Douglas 

County spoke at the public meeting in Roseburg on January 23, 2007, and Douglas 

County has agreed to be a cooperating agency in the production of the EIS for this 

project. 

Question 3b. Please explain how the impacts of pipeline construction are being 

considered as part of the terminal siting process. 

Answer. The Commission’s Order No. 665 governing the requirements for the 

mandatory pre-filing process for LNG terminals states that pipelines necessary to 
75

take gas away from the terminal also fall under the mandatory pre-filing requirements. Consequently, pre-filing review of LNG terminals and their associated pipelines is concurrent. Similarly, the Commission requires LNG terminal and pipeline 

applications be filed at the same time. Commission staff’s draft EIS will be a comprehensive environmental document that addresses potential project impacts of both 

the LNG terminal and the associated sendout pipeline. 

Question 3c. You have said that FERC is not an economic regulator when it comes 

to siting LNG terminals. Please explain how this is consistent with FERC’s responsibilities under the Natural Gas Act under which FERC has been granted authority 

to permit LNG terminals, generally, and with regard to permitting of the ancillary 

pipelines, specifically. 

Answer. When determining whether a proposal to construct and operate an LNG 

terminal is consistent with the public interest, the Commission’s primary considerations are safety and security. We will not authorize a plant to go forward unless 

we are convinced that all legitimate safety and security concerns can be met. Commission staff, and the Commissioners, expend a great deal of effort in thoroughly 

reviewing these applications, in working with the Coast Guard, the U.S. Department of Transportation, and other federal, state, and local agencies and entities, 

and in examining existing information and developing a complete record, so that we 

authorize only those projects that will not pose a significant risk to the public, and 

which comply with all relevant standards. 

Under the Commission’s Hackberry policy, we review new LNG terminals under 

section 3 of the Natural Gas Act, not section 7. For that reason, we do not set rates 

for LNG import facilities or make a need finding, as we would under section 7. Congress largely codified the Hackberry policy in section 311 of EPAct 2005. In section 

311, Congress precluded the Commission from (1) denying an LNG terminal application solely on the basis that the applicant proposes to use the terminal exclusively 

or partially for gas that the applicant, or an affiliate, will supply to the facility, or 

(2) from conditioning an order on a requirement that the terminal offer service to 

anyone other than the applicant or an affiliate, any regulations of rates, charges, 

terms or conditions of service, or a requirement to file with the Commission schedules or contracts. In my view, this has significantly lessened the scope of economic 

issues that the Commission may consider with respect to proposed LNG terminals. 

The Commission’s role as an economic regulator of LNG import facilities is quite 

limited. For example, section 311 provides that an order issued for an LNG terminal 

that offers open-access service shall not result in a subsidy of the expansion service 

by existing customers, degradation of existing service, or undue discrimination 

against existing customers. Moreover, the Commission continues to exercise more 

comprehensive regulation over natural gas pipelines, including those associated with 

LNG import terminals. All such pipelines, which the Commission authorizes pursuant to section 7 of the Natural Gas Act, are required to provide service on an openaccess basis, pursuant to tariffs filed with the Commission. 

Question 4a. The U.S. Coast Guard’s ‘‘Waterway Suitability Report for Bradwood 

Landing,’’ dated February 28, 2007, concludes observing that the LNG terminal proposes to receive vessels with up to 200,000 cubic meters of cargo capacity, but that 

the risk analysis typically used for LNG tanker safety assessments authored by 

Sandia National Labs (the ‘‘Sandia Report’’), is based on ‘‘consequences of LNG 

breaches, spills, and hazards’’ associated with LNG vessels having a cargo capacity 

no greater than 148,000 cubic meters and spill volumes of 12,500 cubic meters. The 

Coast Guard concluded that ‘‘(t)here remains some question as to the size of hazard 

zones for accidental and intentional discharges and the potential increased risk to 

public safety from LNG spills on water for larger vessels.’’ As a result, the Coast 

Guard determined that it will not allow any LNG vessels larger than the size addressed in the Sandia Report until additional analysis is completed. Needless to say, 

this conclusion raises significant questions about the safety of these projects as 

originally proposed and the extent to which there is an adequate technical basis for 

judging the safety of these projects and related tanker movements. (Recently, the 

Government Accountability Office convened an expert panel to assess LNG safety 

risks and unclassified risk assessments which also raised a number of questions 

concerning the adequacy of LNG risk methodologies.) 

Please explain the basis upon which FERC is determining the safety of the 

projects as proposed. What analyses and analytical tools will FERC use to ensure 

that these projects are safe both in accident conditions and from natural events such 

as earthquakes, tsunamis, and floods, inherent to our coastlines? 

Answer. The Commission’s regulations, at 18 CFR 380.12h, have requirements for 

Resource Report 6—Geological Resources that include addressing geological hazards 

such as from seismic ground motions, fault rupture and liquefaction. The proposed 

design concepts and approach to be used in the design of the LNG facilities by the 
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applicant for natural events are required to be addressed in Resource Report 13. 

The Commission requires that LNG facilities built in the United States satisfy the 

requirements of 49 CFR Part 193. For seismic design loads and other natural 

events, 49 CFR Part 193 references an industry standard NFPA 59A ‘‘Standard for 

the Production, Storage and Handling of Liquefied Natural Gas’’ as the basis for the 

design criteria. For LNG facilities in seismic risk areas, the applicant must prepare 

a report on earthquake hazards and engineering design in conformance with ‘‘Data 

Requirements for the Seismic Review of LNG Facilities’’ (NBSIR 84-2833). In addition, the facility design for both the Bradwood Landing and Jordan Cove projects 

will also need to satisfy the most current building code design requirements for the 

State of Oregon, which are provided in the 2007 Oregon Structural Specialty Code. 

Both Northern Star and Jordan Cove have filed project-specific geotechnical and 

seismic hazard reports. Those reports were reviewed by Commission staff and our 

geotechnical consultants. In addition, these reports were independently reviewed by 

the Oregon Department of Geology and Mineral Industries (DOGAMI). In the case 

of the Jordan Cove Project, resource specialists from the U.S. Department of Agriculture Forest Service (USFS) and U.S. Department of the Interior Bureau of Land 

Management (BLM), who are cooperating agencies, also reviewed the draft Resource 

Reports and issued data requests to clarify information and fill data gaps. 

Resource reports filed by both Northern Star and Jordan Cove also addressed potential project impacts from flooding and tsunamis. Again, these reports were reviewed by the Commission staff, our geotechnical consultants, DOGAMI, and, in the 

case of Jordan Cove, by the USFS and BLM. Northern Star plans to raise the elevation of the Bradwood Landing LNG terminal, using fill from dredging of its marine turning basin, to be above the 100-year flood level. The tsunami hazard map 

prepared by DOGAMI for the lower Columbia River showed that only nominal inundation would occur just downstream from Bradwood Landing in the event of a major 

earthquake along the Cascadia Subduction Zone and resulting tsunami. 

The DOGAMI tsunami hazard map for the Jordan Cove LNG terminal location 

showed a potential wave run-up height of 20 feet above sea level. Given the uncertainty associated with tsunami wave run-ups, Jordan Cove is designing its facility 

to include a protective barrier around its proposed LNG storage tanks that would 

be 45 feet above sea level. 

The Commission also has on staff a team of LNG engineers and consultants who 

verify the design hazard levels and analyze the project’s engineering design to make 

certain it can be built in a safe manner. Our team uses computer tools such as the 

analytical programs developed by the U.S. Geological Service to verify the design 

ground motions for both the Bradwood and Jordan Cove sites. Our team has also 

used computer tools such as SHAKE to independently verify the behavior of soils 

to amplify ground motions. In addition, our team has also checked foundations for 

the potential effects of liquefaction, slope stability, settlements and pile deformation 

using computer programs STABLM, LPILE and SETTL/G. Throughout the pre-filing 

process, the Commission team has been working proactively with Oregon state 

agencies to assure that all seismic hazard issues of concern will be mitigated. 

In addition, our regulations at 18 CFR 380.12o require an applicant to address 

how the proposed engineering design would comply with 49 CFR Part 193 and the 

NFPA 59A LNG Standards. The 59A Standard presents various design spills depending on the: type of equipment served by each spill impoundment; the type of 

tank; and the location/size of any penetrations into the tank. The distance to potential effects from these accidental spills are used to establish exclusion zones which 

are based on both the downwind distance flammable vapors may travel and the distance to specified radiant heat flux levels. For a spill which does not ignite, the distance from a design spill into an impoundment to the furthest edge of a flammable 

vapor cloud (i.e. 2.5% concentration of gas in air) must not extend beyond any plant 

property line which can be built upon. In the event of an ignited spill, the distance 

from the pool to the 10,000-, 3,000-, and 1,600 BTU/ft2-hr thermal flux levels must 

be considered. During the project review required prior to any Commission decision, 

Commission staff use the DEGADIS and LNGFIREIII models specified by the federal regulations to verify that the exclusion zones are in compliance with the siting 

standards contained in 49 CFR Part 193. Compliance with Part 193 ensures that 

damaging effects from an on-site accident would not impact public safety. 

The Commission oversight continues after an LNG import terminal project commences commercial operations and extends throughout the life of the project. Each 

LNG facility under Commission jurisdiction is required to file semi-annual reports 

to summarize plant operations, maintenance activity and abnormal events for the 

previous six months. LNG facilities are also required to report significant, nonscheduled events, including safety-related incidents and security-related incidents, 

as soon as possible, but no later than within 24 hours. In addition, Commission staff 
77

9See Distrigas Corporation v. FPC, 495 F.2d 1057 (1974). 

conducts annual on-site inspections and technical reviews of each import terminal 

throughout its entire operational life. The inspection reviews the integrity of all 

plant equipment, operation and maintenance activities, safety and security systems, 

any unusual operational incidents, and non-routine maintenance activities during 

the previous year. Ultimately, the Director of the Office of Energy Projects has the 

authority to take whatever measures are necessary to protect life, health, property 

or the environment. The Director can issue a stop work order during construction 

and can suspend LNG terminal operations if necessary. 

Question 4b. Also, please explain how FERC will address project design and economics consistent with a Coast Guard finding that tankers larger than 148,000 

cubic meters may not be used in the absence of risk analyses covering larger vessels. 

Answer. Currently, Sandia National Laboratory is analyzing risks and safety implications which may be associated with LNG carriers up to 265,000 cubic meter capacity. On April 18, 2007, the Coast Guard issued guidance on modeling LNG spills 

from larger-sized LNG carriers as an interim measure until the Sandia report is 

completed and published. This guidance is to be used by applicants to conduct independent, site-specific modeling to determine the ‘‘Zones of Concern’’ to be used in 

the waterway suitability assessment process. 

As stated in the Coast Guard’s Waterway Suitability Report for the Bradwood 

Landing LNG project, the applicant must either complete this site-specific analysis 

for the largest-sized LNG vessel proposed to visit the terminal or limit arrivals to 

vessels no greater than 148,000 cubic meters until the additional analysis addressing vessels with higher cargo capacities is completed. Should the terminal be authorized and constructed, no ships will be allowed by the Coast Guard or the Commission to service the terminal unless both agencies’ review indicates that larger 

vessels can be used safely. 

Question 5a. Although some elements of the Coast Guard’s assessment are restricted from public disclosure, including specific resource gaps in level of law enforcement and security assets necessary to safeguard these terminals and tanker 

movements, the Waterway Suitability Report does identify a significant number of 

resource gaps at all levels—from water-borne and shore-side fire fighting capability, 

to natural gas detection, to interagency communications, to vessel traffic control assets, to Coast Guard and law enforcement assets. 

How will FERC ensure that such resource gaps are filled as a condition of approval? 

Answer. Each Commission order authorizing an LNG import terminal requires 

the LNG terminal operator to develop an Emergency Response Plan in consultation 

with the U.S. Coast Guard and state and local agencies. The Emergency Response 

Plan must also include a cost-sharing plan and must be approved by the Commission prior to any construction at the facility. The cost-sharing plan specifies what 

the LNG terminal operator would provide to cover the cost of the state and local 

resources required to manage the security of the LNG terminal and LNG vessel, and 

the state and local resources required for safety and emergency management. This 

process provides a mechanism for filling any resource gaps that have been identified 

in the Waterway Suitability Report. No construction of an LNG terminal is permitted until an Emergency Response Plan with cost sharing is approved by the 

Commission. 

Question 5b. What is FERC’s statutory authority to do so? 

Answer. As amended by Section 311 of EPAct 2005, section 3 of the Natural Gas 

Act requires that the Commission require and approve the cost-sharing plan.. Further, under section 3, the Commission ‘‘may by its order grant such application, in 

whole or in part, with such modifications and upon such terms and conditions as 

the Commission may find necessary or appropriate . . .’’.9

Question 6a. The U.S. Coast Guard indicated that a moving safety/security zone 

would be established around the LNG vessel, extending 500 yards around the vessel, but ending at the waterfront. Much of the Astoria waterfront would fall within 

this 500 yard zone. We would expect a similar situation to arise in the small harbor 

at Coos Bay. The Coast Guard indicates that its jurisdiction only extends to the 

shoreline for vessels in transit and not to impacts onshore. 

Will FERC use the same 500 yard safety and security zone proposed by the Coast 

Guard for in-transit safety and security? If not, what zone will FERC establish and 

on what basis? 

Answer. Although the Commission is the lead federal agency under NEPA to analyze the environmental impacts and safe engineering design of the proposed onshore facilities, the Coast Guard has regulatory authority over safety and security 
78

of the LNG marine traffic. In conjunction with this, the Coast Guard determines the 

suitability of waterways for LNG marine traffic by issuing a Letter of Recommendation (LOR) and by establishing the operational restrictions that would control LNG 

carrier transit, including, for example, the 500-yard safety and security zone. In accordance with 33 CFR 127 and Navigation and Vessel Inspection Circular 05-05, the 

Coast Guard Captain of the Port would issue a LOR which incorporates the initial 

findings of the Waterway Suitability Report. 

Question 6b. How will FERC address the need to ensure the safety and security 

of residents onshore who are within 500 yards or such other safety and security 

zone it chooses to establish from the ship and terminal? 

Answer. As identified in my response to your question 6a, the Coast Guard establishes safety and security zones around the LNG marine traffic. Both waterway and 

shoreside safety and security are considered during the assessment process. Safety 

and security are provided by a comprehensive scheme of coordinated federal, state, 

and local agencies for both the onshore facility and the waterborne vessel. The process allows port-by-port measures to be developed so the appropriate level of control 

is exercised. 

In the case of the onshore terminal, the Commission staff ensures that the proposed facility meets the federal siting regulations under 49 CFR Part 193. In accordance with these regulations, exclusion zones associated with onshore LNG containers and transfer systems must either remain within the facility property line or 

must be legally controlled by the facility operator. These zones exist to ensure there 

would be no significant off-site impact to the public from an incident involving the 

LNG import terminal equipment. During the review performed for each project, 

Commission staff calculates the exclusion zones associated with the terminal to ensure the facility would be in compliance. If a site does not meet these federal requirements, it would not be approved. 

While the Coast Guard process addresses safety and security along the waterway, 

it gives consideration to shoreside support issues and also the Emergency Response 

Plan required by EPAct 2005 that addresses the safety and security of the land 

areas adjacent to the LNG vessel transit route. Detailed shoreside procedures and 

appropriate measures are determined during development of the LNG Vessel Transit Management Plan. This more detailed planning engages the appropriate law enforcement and emergency responders. Any Commission order authorizing an LNG 

terminal must require this Emergency Response Plan to be developed in consultation with the Coast Guard and state and local agencies and approved by the Commission prior to any final approval to begin construction. At a minimum, this plan 

would address scalable procedures for the prompt notification of appropriate local 

officials and emergency response agencies based on the level and severity of potential incidents. In addition, the plan would include notification procedures and evacuation routes/methods for residents and other public use areas that are within any 

transient hazard areas along the route of the LNG marine transit. The requisite 

cost-sharing plan which must be included in the Emergency Response Plan would 

ensure that state and local resources would be available for security and safety both 

at the proposed facility and along the transit route. 

Question 7. What is FERC’s authority to ensure that all safety and security requirements and obligations continue to be met after an LNG facility is approved and 

constructed? 

Answer. The Commission has full authority to ensure that all safety and security 

requirements and obligations are met after an LNG facility is approved and constructed. Our authority does not end upon approval of the project. As amended by 

section 311 of EPAct 2005, Section 3 of the Natural Gas Act provides the Commission broad, exclusive authority to approve or deny applications for the siting, construction, operation, or expansion of LNG terminals. Under section 3, the Commission ‘‘may by its order grant such application, in whole or in part, with such modifications and upon such terms and conditions as the Commission may find necessary 

or appropriate . . .’’ See Distrigas Corporation v. FPC, 495 F.2d 1057 (1974) (holding that, under section 3, the Commission’s authority over LNG facilities is ‘‘plenary 

and elastic,’’ that the Commission must exercise under section 3 ‘‘the same detailed 

regulatory authority that it exercises [under NGA section 7] with respect to interstate commerce in natural gas’’ and that it can impose ‘‘the equivalent of section 

7 certification requirements as to [LNG] facilities . . .’’). 

For example, all Commission orders authorizing LNG import terminals contain 

reporting requirements for semi-annual operational reports, as well as requirements 

for immediate notification for any safety or security related incidents, and a condition requiring the facility be subject to Commission staff technical reviews and site 

inspections on at least an annual basis. The Commission reorganized the LNG staff 

to designate a Compliance Branch whose function is to monitor and inspect LNG 
79

10 AquaEnergy Group, LTD, 102 FERC Paragraph 61,242 (2003). 11See, e.g., Presidential Proclamation No. 5928 (December 12, 1988), 103 Stat. 2981 (asserting 

jurisdiction up to 12 nautical miles). 

facilities during construction and operation to ensure project safety. In addition, 

Commission orders contain a condition giving the Director of the Office of Energy 

Projects authority to take all steps necessary to ensure the protection of life, health, 

property, and the environment during construction and operation of the import facility. This authority includes the right to stop work or operations at the terminal 

should conditions warrant and has been used effectively by Commission staff. These 

requirements and conditions remain in effect for the operational life of the facility. 

The Commission will not authorize an LNG terminal unless the applicant accepts 

these conditions. 

Question 8a. Based on your letter to me, and your testimony before the Committee, FERC places a significant role on the Environmental Impact Statement 

(EIS) process for collecting and responding to comments and concerns not only from 

the public, but from state and local government agencies. On April 9, 2007, the Oregon Department of Energy made a request to FERC to extend the comment period 

for that Draft EIS from 45 days to 120 days because ‘‘a 45 day review is insufficient 

for what we expect to be a voluminous and complex document.’’ Our State agencies 

are trying to cope with three LNG projects, and the new pipelines that go along 

with them, simultaneously. They are doing the vast bulk of this work without being 

able to recover any of their costs through application fees and so they resources are 

stretched very thinly. 

Are you going to approve the Oregon extension request? 

Answer. As you indicate, this request is currently pending before the Commission 

and I cannot prejudge disposition of this matter. Comment deadlines are important 

to our ability to process applications for new infrastructure projects on a timely 

basis, but we have the discretion to waive deadlines for good cause. 

Question 8b. In your response to Congressman Baird and in your testimony before 

the Committee you stated that the Commission staff will take into account comments made after the comment period closes, implying that the close of the formal 

comment period has no legal meaning. What is the legal basis for this conclusion 

and what assurance will state agencies and others have that their comments will 

be valid and part of the NEPA and permitting records? 

Answer. Under NEPA, the Commission must prepare a draft and final EIS before 

taking a major federal action that affects the environment. We establish comment 

deadlines during preparation of the draft and final EIS. However, neither NEPA nor 

the Natural Gas Act require that we disregard late comments, and it has been our 

longstanding practice to accept late comments, provided we have time to consider 

those comments before issuing the final environmental document. I appreciate the 

resource demands on your state agencies and can assure you they will be accounted 

for in considering the extension request. 

Question 9. Both FERC and the Mineral Management Service claim jurisdiction 

over the permitting of wave energy projects on the Continental Shelf. FERC apparently believes that navigable water as defined by the Federal Power Act includes 

coastal and offshore waters. MMS believes that Congress, in the 2005 Energy Act, 

gave it jurisdiction over offshore alternative energy development. Why do you believe that FERC has jurisdiction over wave energy projects in coastal and offshore 

waters and has this interpretation ever been reviewed by a court? What steps have 

you taken or will you take to ensure that developers of coastal alternative energy 

projects do not have to comply with duplicative or conflicting MMS and FERC siting 

and permitting requirements? Do you believe that additional legislation is needed 

to clarify the roles and authorities of the two agencies in this regard? 

Answer. As the Commission explained in AquaEnergy Group, LTD, FPA section 

23(b)(1) defines those facilities that are required to be licensed by the Commission 

to include project works across, along, or in any of the navigable waters of the 

United States.10 Section 3(8) of the FPA defines ‘‘navigable waters’’ as ‘‘those parts 

of streams or other bodies of water over which Congress has jurisdiction under its 

authority to regulate commerce with foreign nations and among the several States, 

and which either in their natural or improved condition... are used or suitable 

for use for the transportation of persons or property in interstate or foreign 

commerce . . .’’. The definition of ‘‘navigable waters’’ encompasses streams and 

other bodies of water over which Congress has Commerce Clause jurisdiction, and 

includes the use of such waters in ‘‘foreign commerce.’’ The United States has asserted jurisdiction over waters well offshore.11 Thus, the Commission concluded that 

a plain reading of the FPA indicates that the Commission has jurisdiction to license 

projects in offshore navigable waters. No court has reviewed this finding. However, 
80

Commission orders have the full force and effect of law unless and until overturned 

by the courts. AquaEnergy filed an appeal in the U.S. Court of Appeals for the District of Columbia Circuit, but asked the court to hold the appeal in abeyance, and 

has instead filed a license application with the Commission. The alternate energy 

provisions of EPAct 2005, which otherwise grants authority to MMS over alternate 

energy projects on the Outer Continental Shelf, contained a saving clause providing 

that: ‘‘Nothing in this subsection displaces, supersedes, limits, or modifies the jurisdiction, responsibility, or authority of any Federal or State agency under any other 

Federal law.’’ Thus, assuming that the Commission’s initial interpretation of the 

FPA was correct, EPAct 2005 did not alter the Commission’s offshore jurisdiction. 

Commission and MMS staffs are currently developing a memorandum of understanding (MOU) with the goal of reaching agreement on a process that will allow 

both agencies to develop an efficient and effective program for promoting and regulating the development of hydropower in offshore areas. Both agencies share this 

goal, and the discussions have been productive. The current target date for execution of the MOU is early summer 2007. I recommend allowing the two agencies to 

attempt to establish an efficient and effective program by administrative action, 

rather than legislate in this area. 

Question 10. Last year, to your credit, FERC held a technical conference on new 

hydroelectric technologies for wave energy and tidal projects. As you acknowledged 

at the time, these technologies have enormous potential to provide us with a clean, 

renewable source of energy, and you should get credit for examining how FERC 

should address these new technologies. But in February, when FERC came out with 

a proposal to improve the permitting process for these new technologies, there was 

really nothing new. To cite the FERC press release, FERC sought comment on three 

alternatives:

a. Maintain the standard preliminary permit review process currently in use. 

b. Provide stricter scrutiny of permit applications and limit the boundaries of 

the permits to prevent site-banking and promote competition. 

c. Decline to issue preliminary permits for these new technologies altogether.

It seems to me that whether or not FERC has more or less scrutiny of these preliminary applications is a secondary issue. None of these technologies is truly at the 

commercial deployment stage. They are at the developmental and demonstration 

stage. We do not know which technologies will actually work at commercial scale. 

The challenge here is to develop a process that recognizes the state of the technology and will allow it to be tested and demonstrated and your proposal doesn’t 

really seem to do so. How does your proposal to revise the permitting process address the basic issue facing these technologies which is their lack of technological 

maturity? 

Answer. I believe our proposal to improve the preliminary permit process does 

help promote and facilitate the development of this new technology and was largely 

supported by public comments. Since we adopted this policy, we have issued 35 preliminary permits. A preliminary permit does not authorize the installation and actual testing of demonstration equipment in the water. The sole purpose of a permit 

is to reserve a site and give the permittee the right to file a license application at 

that site over other competitors. During the term of a permit, a permittee consults 

with state and federal agencies and conducts studies and other activities leading to 

the preparation of a license application. 

Our February 15, 2007 Notice of Inquiry (NOI) listed three alternatives to deal 

with preliminary permits for new technologies. In the NOI commenters were encouraged to suggest additional alternatives. The NOI also stated that in the interim we 

would be using the strict scrutiny approach, which was overwhelmingly supported 

in the comments to the NOI. This means that we are asking the applicants to provide a specific technology and a realistic justifiable project boundary. We are also 

placing conditions on issued permits to ensure that the permittees are diligently 

pursuing the development of these projects. If a permittee is not diligently pursuing 

development, then the Commission can terminate the permit. Our new policy responds to stated concerns about banking of promising sites for deployment of these 

new technologies. 

The revised approach promotes new technology in several ways. It would limit a 

permittees’ ability to engage in site banking (that is, holding sites for speculative 

purposes), thereby ensuring that sites remain open and available to serious developers to study and test their technologies. By requiring the applicant to provide information on the specific technology and sizing its study area in relation to its proposal, the revised approach also encourages applicants to select and narrow its focus 

of study to a specific technology among many new concepts that are available. Also, 
81

by carefully scrutinizing a permittee’s progress under a permit, we are ensuring 

that a permittee is diligently pursuing the development of that specific technology. 

The deadline to file comments on the NOI was May 1, 2007, and the Commission 

received numerous comments. Commission staff will review all the comments filed 

and will make recommendations to the Commission for a revised process for preliminary permits that facilitates and promotes the development of these new energy 

technologies. As I discuss below, in response to your next question, the Commission 

is exploring ways to adapt its processes to encourage the testing and development 

of new technologies. 

Question 11. In April 2005, FERC issued an order allowing Verdant Power to conduct testing at a site in the East River in New York City for a tidal energy project. 

(You were a member of the Commission at the time.) To quote from the order, 

‘‘(t)his order is in the public interest because it clarifies that, under limited circumstances, experimental hydroelectric facilities may be tested without the need for 

a license.’’ Why didn’t we see some sort of regulatory mechanism or exemption for 

experimental testing of new technologies in your February proposal? If it made 

sense to allow testing of tidal turbines in the East River, why doesn’t it make sense 

to allow the testing of other technologies in other locations? 

Answer. The potential for experimental deployments without a hydropower license 

set out in the Verdant order may be available to other developers with other technologies at other locations. In fact, under this policy, we understand that wave developers are planning experimental deployments in the near future. In particular, 

Lincoln County, Oregon is planning to deploy three experimental wave buoys off its 

coastline within a year. 

In the Verdant decision, the Commission determined that Verdant Power could install its six-turbine demonstration project in the East River without applying for a 

Commission license. In a July 27, 2005, Order on Clarification, the Commission concluded that Verdant’s activities effectively would have no net impact on the interstate electric power grid or on interstate commerce. This determination established 

a policy that allows experimentation without a license when 1) the technology in 

question is experimental; 2) the proposed facilities are to be used for a short period 

and for the purpose of developing a hydropower license application; and 3) power 

generated from the test project will not be transmitted into, or displaced from, the 

national electric energy grid. In addition to testing power generation, Verdant will 

carry out extensive monitoring of fishery impacts as part of the experimental deployment. Although not required to be licensed during its testing phase, Verdant 

was of course obligated to obtain necessary approvals under other existing state and 

federal statutes. 

I am aware of concerns that this decision may be of limited applicability. Staff 

is investigating ways to supplement or improve this policy, within the constraints 

of Part I of the FPA, which requires that hydropower projects subject to the Commission’s jurisdiction be licensed. We believe we have some tools under the FPA to 

improve the system for experimental deployments. To this end, staff is exploring options to determine the best approach. It is too early to suggest what the outcome 

will be, but I am committed to ensuring that we will use the full range of our authority to facilitate the testing and development of new technologies in this area. 

Question 12. In the five and a half years after Enron’s collapse, it seems that 

FERC is still going through the motions of unraveling what Enron did to our energy 

markets in the West. In March, as a result of unflagging efforts of Snohomish PUD, 

one of the municipal utilities in Washington state, the FERC administrative law 

judge in that case essentially concluded that Enron had deliberately withheld information from FERC on its electricity trading activities back in 2001 when FERC 

began to examine whether our Western markets had been manipulated. In fact, 

Judge Cintron asked the Commission to determine whether Enron’s lawyers and the 

consultant that withheld the data should be suspended or disqualified from practicing before FERC. To your credit, the Commission agreed to initiate a proceeding 

to look at that question, but there is a bigger issue in the room. If Enron withheld 

information from FERC in its original Northwest price manipulation proceeding, 

what is the Commission going to do about revisiting its conclusions in that investigation, particularly as they relate to Enron? 

Answer. The Commission’s order initiating this proceeding required the presiding 

judge to address very specific questions and make a recommendation to the Commission. On May 15, 2007, the presiding judge made comments from the bench indicating that he does not believe that unethical or unlawful conduct occurred. However, the presiding judge is required, pursuant to our April 11, 2007 order, to make 
82

12 Enron Power Marketing, Inc., 119 FERC 61,036 (April 11, 2007). 13 Enron Power Marketing, Inc., Docket No. EL03-180-029 (order issued April 25, 2007). 

very specific findings in a written decision.12 Parties will have an opportunity to 

comment on the presiding judge’s decision. Until those findings are made and the 

Commission has an opportunity to consider the full record before it, I cannot comment on whether any violations occurred and, if so, what remedies are appropriate. 

Question 13. The Commission’s decision to follow Judge Cintron’s advice and look 

at the behavior of Enron’s lawyers and consultants also highlights a related issue, 

and that is the Commission’s routine practice of making essentially every bit of information in these sorts of proceedings restricted from public release and the subject 

of blanket protective orders. In this case, for example, the Commission is going to 

be examining information that Enron submitted to FERC more than five years ago, 

and the very first thing that FERC did was make all of the information relevant 

to this proceeding subject to a blanket protective order as it does for virtually every 

such proceeding. I understand that there is a general need to protect information 

that might compromise an ability of a company to do business, but Enron’s not in 

the energy trading business any more. When are citizens in the Northwest going 

to get a chance to find out what really happened to our electricity prices in 2000 

and 2001? Don’t you think there needs to be a balance between the corporate interest to restrict access and the public interest to understand the facts and see the evidence not just in this case, but in others as well? 

Answer. I agree that there must be a balance between the proprietary interests 

of commercial parties and the public need for information. Another factor is the 

need to ensure the government’s ability to prosecute wrongdoing. Specifically, much 

of the information concerning Enron was obtained initially by the U.S. Department 

of Justice, which then supplied information to the Commission and other agencies 

pursuant to a court order that it not be disclosed without authorization. This restriction was aimed at protecting the Justice Department’s ability to prosecute cases 

against Enron executives. Last month, the court authorized public release of certain 

documents used as evidence in the Commission proceeding against Enron. 

In the more recent dispute you mention above, the presiding judge adopted a protective order for two types of information: (1) materials customarily treated by a 

party as sensitive or proprietary, not available to the public, and which, if disclosed, 

‘‘would subject that Participant or its customers to risk of competitive disadvantage 

or other business injury;’’ and (2) materials containing ‘‘critical energy infrastructure 

information.’’13 This type of protective order is used at times in Commission proceedings, and allows the parties to obtain information from other parties through 

discovery, yet defer litigation about whether public disclosure would risk undue 

harm. Facilitating quick but broad discovery in this way allows the litigants to crystallize the issues in dispute efficiently. Once the litigants present their evidence, the 

presiding judge and the Commission can then decide whether non-public information is relevant to the outcome of the case and, if so, can determine whether a claim 

of confidentiality is justified. In its adjudications, the Commission’s general practice 

is not to withhold from its public orders any information that was relevant to the 

resolution of disputed issues. 

Question 14a. Despite repeated efforts by BPA and others to educate FERC on 

how the system works in the Northwest, FERC, in Order 890, has once again proposed one-size-fits-all transmission service rules that simply don’t fit all. For example, the FERC rule requires that utilities report the generating source for power 

that they purchase within the region in which they operate. That might make sense 

as a general rule, but when it was pointed out to FERC that there are almost 100 

utility companies within the BPA region that buy hydropower from the BPA system 

and do not know which dam the electricity actually comes from yet FERC essentially said it would require them to report it anyway. These existing practices are 

not causing discriminatory access to the transmission system but are critical to 

achieving the efficient and economic provision of electricity service throughout the 

region. This seems to be a case where FERC, in its effort to establish a nation-wide 

rule is actually damaging operating markets. 

Why has FERC largely ignored the comments of utilities in the Northwest and 

another Federal agency—the Bonneville Power Administration—in issuing and interpreting its new transmission regulations related to these issues? 

Answer. I do not believe Order No. 890 has a ‘‘one-size-fits-all’’ approach. It was 

important to me that the order show regional flexibility. Similarly, I do not believe 

that the comments of utilities in the Northwest were ignored. We addressed more 

than one hundred issues in our 1,200 page rulemaking and, in doing so, adopted 

positions advocated by Northwest participants on many occasions. For example, the 

Commission adopted a new framework for energy imbalances that was proposed by 
83

BPA and supported by entities throughout the Northwest. We also adopted a flexible and regional approach to transmission planning that was supported by the 

Northwest participants. 

As I understand the specific issues addressed in your question, BPA and other 

Northwest market participants are concerned with the Commission’s pro forma open 

access transmission tariff provisions relating to designation of network resources 

and the ability of on-system seller’s choice and system sales agreements to qualify 

as network resources. The Commission’s network resource designation rules were 

developed to ensure that a network customer designating resources provides sufficient information to allow the transmission provider to determine the effect of such 

designation on the transmission provider’s available transfer capability (ATC). ATC 

represents the transmission capacity available for sale to other market participants 

and therefore is critical to the functioning of competitive markets. Because on-system seller’s choice and system sales agreements can significantly obscure the calculation of ATC, they raise concerns about planning, efficiency and discrimination. 

The Commission’s goal in Order No. 890 was to encourage more transparent ATC 

calculation and to avoid inputs that are so vaguely defined that the effects on ATC 

cannot be determined, which would permit the exercise of undue discrimination. As 

such, in Order No. 890 the Commission clarified its pro forma tariff provisions relating to the information that must be provided when designating network resources; 

however, the Commission recognized that there may be cause for deviations from 

the pro forma tariff where transmission providers can demonstrate that such deviations are consistent with or superior to the pro forma tariff provisions. 

In their requests for rehearing and clarification, BPA and other Northwest market 

participants have raised important points about their reliance on hydroelectric 

power and how the Commission’s clarifications with regard to on-system seller’s 

choice and system sales will affect them. These requests include a good deal of additional detail, which the Commission currently is carefully considering. In addition, 

since the Commission’s ex parte prohibitions do not apply to rulemakings, Commission staff has invited BPA and others to discuss their specific concerns in advance 

of a Commission order on rehearing of Order No. 890. I can assure you we will carefully consider the arguments of these parties and their specific circumstances. 

Question 14b. There are serious concerns that the proposed OATT rules will damage the pre-schedule and real-time markets in the NW. What assessments has 

FERC conducted to determine the impacts its proposal would have on the reliability 

or cost of electric service in the NW region? 

Answer. This concern appears to relate to the pro forma tariff provision, adopted 

in Order No. 890, adopting a minimum lead-time for undesignating network resources to make firm third-party power sales. Order No. 890 established that minimum lead time to mirror the deadline for scheduling firm point-to-point transmission service adopted in Order No. 888. As the Commission adopted a minimum 

undesignation lead time in Order No. 890 to coincide with the existing scheduling 

deadline for point-to-point transmission in the pro forma tariff established in Order 

No. 888, it did not expect any significant effect on any market, as most parties use 

firm point-to-point service to transmit firm third-party power sales. Moreover, under 

Order No. 888, the scheduling deadline provision of the pro forma tariff specifically 

contemplated regional variations that reflect ‘‘a reasonable time that is generally accepted in the region and is consistently adhered to by the transmission provider.’’ 

In addition, the Commission in Order No. 890 made clear that transmission providers with existing approved deviations from the pro forma tariff that were not 

changed in Order No. 890 would be allowed to retain such variations. Accordingly, 

if a transmission provider had a firm point-to-point scheduling deadline variation 

from the pro forma tariff, then that deadline would also apply to its undesignations. 

Order No. 890 made clear that any transmission providers that desired a deviation 

from the pro forma tariff are free to submit them to the Commission pursuant to 

section 205 of the FPA. 

In response to your more general question, the Commission currently is evaluating requests for rehearing and clarification of Order No. 890, including a number 

of requests that address the issues raised in your question. In addition, the Commission has received a request to convene a technical conference with Commission staff 

to discuss the effects on Western utilities of the minimum lead-time for 

undesignating network resources. The Commission is carefully evaluating these requests to assess the impact of its rules on the region. 

Question 14c. How will FERC ensure that any rules you adopt to ensure robust 

markets and safe and adequate transmission also apply to federal power marketing 

agencies and publicly-owned utilities that participate in wholesale markets or, if the 

rules do not apply to these entities, that the application of the rules to the investor-
84

owned utilities in such regions do not result in harm to either the reliability or economics of their retail electric service? 

Answer. The Commission’s open access rules apply to all public utilities that own, 

control or operate facilities used for the transmission of electric energy in interstate 

commerce. In Order No. 888, however, the Commission conditioned non-public utilities’ (primarily governmental and electric cooperative utilities) use of public utility 

open access service on the non-public utilities’ agreement to offer comparable transmission services in return. Under this so-called ‘‘reciprocity’’ condition, therefore, a 

federal power marketing agency or publicly-owned utility that takes open access 

transmission service from a public utility transmission provider is required to provide comparable transmission service that it is capable of providing on its own system. In addition, Congress in EPAct 2005 authorized, but did not require, the Commission to order non-public utilities to provide transmission services under a new 

section 211A of the Federal Power Act. In Order No. 890, the Commission indicated 

that it would apply new section 211A on a case-by-case basis, rather than generically. Thus, in addition to the reciprocity condition, the Commission now has additional authority to ensure that its rules ensuring robust markets through open access to transmission apply to all market participants in a non-discriminatory manner. 

With respect to the safety and adequacy of transmission facilities, state regulatory 

bodies have primary responsibility to ensure that all transmission facilities sited in 

their jurisdictions meet safety standards and are sufficient to serve retail customers. 

In addition, the Commission has jurisdiction under section 215(b) of the Federal 

Power Act to approve reliability standards developed by the Electric Reliability Organization, which standards are applicable to ‘‘all users, owners and operators of the 

bulk-power system, including but not limited to the entities described in section 

201(f),’’ which would include publicly-owned utilities and federal power marketing 

agencies. As such, the rules approved by the Commission to ensure the reliability 

of transmission facilities apply equally to public utility transmission providers and 

non-public utility transmission providers. 

Question 14d. What actions will FERC take to monitor impacts of the new GATT 

rules in individual markets, such as the NW, and its impacts on different classes 

of utilities? 

Answer. The Commission has a variety of avenues through which to monitor the 

impact of the new OATT rules. For example, the Office of Enforcement will conduct 

audits and investigate informal complaints and self-reports. These activities typically involve jurisdictional investor-owned utilities, although they could involve nonjurisdictional entities. The Commission also has a formal complaint process where 

it can consider claims of undue discrimination and other violations of the new OATT 

rules. Finally, a number of the reforms that the Commission adopted in Order No. 

890 will result in new reliability standards that will be monitored by both the Electric Reliability Organization, the Commission’s Division of Reliability in the Office 

of Energy Markets and Reliability, and the Commission’s Office of Enforcement. All 

classes of utilities will be subject to these reliability standards. 

RESPONSE OF JOSEPH T. KELLIHER TO QUESTION FROM SENATOR LANDRIEU

Question. Chairman Kelliher, I am told that there are billions of dollars worth of 

major new large diameter trunkline applications pending before FERC. You and 

your team are to be commended: you have developed clear processes and clear 

timelines, and from what I understand, you have generally worked closely with the 

applicants that are making these massive capital commitments, and worked well 

with the other resource agencies and stakeholders. You have developed these processes and timelines, now I need some assurance that you can meet them. Given the 

intense competition for construction contractors, heated competition for the procurement of steel pipe on the international market, and other factors, I believe that 

meeting the timelines that you have proposed is no easy task. However, meeting 

these deadlines will surely be critical to attracting the billions of dollars of capital 

investment necessary to bring large natural gas reserves to market. We need to ensure that the pipeline developers who are bringing natural gas up from the Gulf 

Coast, the Rockies, Oklahoma, Arkansas and other areas do not get penalized by 

delays. Getting this infrastructure in place is also a critical component of our nation’s energy security. So my question is: Does FERC have the resources it needs 

to move these projects along as expeditiously and efficiently as the natural gas markets seem to be demanding? 

Answer. The continuing development of new gas supplies in east Texas, west Louisiana, Arkansas and Oklahoma has sparked the need for increased pipeline takeaway capacity to get these much needed supplies to market. Additional pipeline 
85

14Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 FR 43294 

(July 31, 2006), FERC Stats. & Regs. Paragraph 31,222 (2006). 15 EEI Survey of Transmission Investment: Historical and Planned Capital Expenditures 

(1999-2008) at 3 (2005). 16 Barriers to Transmission Investment, Presentation by Brendan Kirby (U.S. Department of 

Energy, Oak Ridge National Laboratory), April 22, 2005 Technical Conference, Transmission 

Independence and Investment, Docket No. AD05-5-000 (April 22, 2005 Technical Conference). 17 Energy Policy Act of 2005: Hearings before the House Subcommittee on Energy and Commerce, 109th Congress, First Sess. (2005) (Prepared statement of Thomas R. Kuhn, President 

of EEI).

take-away capacity is also needed for increased supplies of Rocky Mountain gas. The 

preponderance of the major pipeline projects currently being proposed connects 

these new supplies and anticipated LNG supplies to the interstate pipeline grid. 

Since the beginning of fiscal year 2007 the Commission has approved two major 

pipelines moving gas from these areas: Centerpoint Energy Gas Transmission Company’s Carthage to Perryville Project and the Rockies Express Western Phase 

Project. In addition, the Commission issued seven draft environmental impact statements (EIS) and five final EISs. Several other major projects are still in the prefiling stage and have not yet filed applications with the Commission. 

Through the use of the Commission’s pre-filing process, the Commission staff has 

been able to expeditiously develop the necessary record to allow the Commission to 

act in a timely fashion. The Commission has been increasing staff resources in several key areas to address changing energy markets. Notably, as a result of the resurgence of LNG as important part of the Nation’s gas supply portfolio, the Commission has significantly enhanced its LNG Engineering and Compliance programs. 

Our current resources are adequate to maintain our efficiency in the Commission’s review of proposed gas infrastructure projects. Should a significant increase 

in workload or additional responsibilities become apparent, the Commission will request the necessary resources to maintain the strength and efficiency of our gas programs. 

RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR SALAZAR

Question 1. Many of our regional power grids are working near their limits, and 

we have seen that they are susceptible to failure. Would the construction of additional transmission lines provide additional reliability and security to our power 

grid? Would increased production of electricity from more geographically distributed 

sources also improve the reliability and security of the national power grid? 

Answer. Yes, as a general matter, the construction of additional transmission 

lines and geographically distributed generation does improve the reliability and security of the bulk power system. The Commission has noted in several generic/noncase specific rulemaking proceedings that the industry as a whole has drastically 

underinvested in transmission for decades. For instance, in Order No. 67914 at P 

10, the Commission stated: 

. . . investment in transmission facilities in real dollar terms declined 

significantly between 1975 and 1998. Although the amount of investment 

has increased somewhat in the past few years, data for the most recent 

year available, 2003, shows investment levels still below the 1975 level in 

real dollars.15 This decline in transmission investment in real dollars has 

occurred while the electric load using the nation’s grid more than doubled.16

Further, the record shows that the growth rate in transmission mileage 

since 1999 is not sufficient to meet the expected 50 percent growth in consumer demand for electricity over the next two decades.17

The transmission incentives contemplated in section 219 of the FPA are intended 

to help mitigate this trend, and have prompted several projects that will improve 

the reliability of the bulk power system in certain areas. However, it will take years 

to reverse decades of underinvestment and many challenges remain. Last summer’s 

nationwide heat wave drove each region of the nation to record peak demands severely straining operating reserves from coast-to-coast. We need to look to all solutions, including transmission, traditional generation, distributed generation, and renewable resources, as well as demand response and conservation, to maintain and 

improve reliability. Without these measures, there is a detrimental impact to the 

reliability and security of the bulk power system and the potential for blackouts remains. 

As I will discuss in the answer to your next question, the Commission is undertaking a number of initiatives to strengthen the nation’s power grid and foster the 

use of renewables and distributed generation. 
86

18See Promoting Transmission Investment Through Pricing Reform, Order No 679, FERC 

Stats. & Regs. Paragraph 31,222 (2006), order on reh’g, Order No 679-A, FERC Stats. & Regs. 

Paragraph 31,236, order on reh’g, 119 FERC Paragraph 61,062 (2007). 19See e.g., American Electric Power Service Corp., 116 FERC Paragraph 61,059 (2006), order 

on reh’g, 118 FERC Paragraph 61,041(2007); Allegheny Energy, Inc., et al., 116 FERC Paragraph 

61,058 (2006), order on reh’g, 118 FERC Paragraph 61,042 (2007). 20See Regulations for Filing Applications for Permits to Site Interstate Electric Transmission 

Facilities, Order No. 689, 71 Fed. Reg. 69,440 (Dec. 1, 2006), FERC Stats. & Regs. Paragraph 

31,234 (2006). 21Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 

72 Fed. Reg. 12,266 (Mar. 15, 2007), FERC Stats. & Regs. Paragraph 31,241 (2007), reh’g pending. 22See Midwest Independent Transmission System Operator, Inc., 117 FERC Paragraph 61,241 

(2006), rehearing denied, 118 FERC Paragraph 61, 208 (2007). 23See Midwest Independent Transmission System Operator, Inc., 118 FERC Paragraph 61,209, 

rehearing pending (2007). 

Question 2. Please provide to this committee a summary of the regulatory policies 

that FERC has considered, whether formally or informally, over the past five years 

or is now considering to encourage: (1) the construction of additional transmission 

lines, (2) distributed generation and (3) the production of electricity from renewable 

sources. Please include FERC ’s determination on each such policy issue and a brief 

explanation for that determination. 

Answer. 

Construction of Additional Transmission Lines 

Over the last five years, the Commission has undertaken a number of significant 

regulatory policies aimed at encouraging the construction of additional electric 

transmission lines. These include: 

Incentives for Building New Transmission.—Last year, the Commission issued a 

major rulemaking pursuant to the requirements of section 1241 of the Energy Policy 

Act of 2005 (EPAct 2005) (new FPA section 219) to establish incentive-based rate 

treatments associated with new transmission infrastructure investment.18 Since enacting the rule, the Commission has acted upon several requests from utilities seeking rate incentives in order to help ensure the reliability of the bulk transmission 

system or reduce the cost of delivered power to customers by reducing congestion.19

Siting Regulations.—Section 1221 of EPAct 2005 (new FPA section 216) provides 

for the federal siting of electric transmission facilities under circumstances where 

the Department of Energy has identified transmission constraints or congestion and 

designated the area as a national interest electric transmission corridor and where: 

a state commission either has no authority to site or cannot consider interstate benefits, the applicant does not serve end-users in the state and thus does not qualify 

for a state permit, a state commission has conditioned approval such that construction will not reduce congestion or is not economically feasible, or a state commission 

has withheld approval for more than one year after the filing of an application seeking approval pursuant to applicable state law. The Commission implemented new 

regulations to establish filing requirements and procedures for entities seeking to 

construct electric transmission facilities under these circumstances.20

Regional Transmission Planning.—In February of this year, the Commission 

issued a final rule reforming its open access transmission rules.21 Among the reforms adopted was a requirement that transmission providers establish a coordinated and open regional transmission planning process. This new process will be 

very helpful in establishing the need and cost responsibility for major transmission 

upgrades needed to support the interstate transmission grid. It will build upon and 

reinforce existing regional planning efforts underway in various parts of the United 

States and Canada. 

Cost Allocation.—Investment in new transmission can be impeded unless investors and consumers know who will be obligated to pay the costs of those investments. The Commission has therefore devoted significant resources to addressing 

cost allocation issues, particularly those arising on a regional basis. For example, 

on November 29, 2006, the Commission issued an order finding that the Midwest 

ISO’s proposed methodology (i.e., 20 percent of a high-voltage baseline reliability 

project’s cost is allocated across the footprint on a load ratio share basis and 80 percent is allocated sub-regionally based on a Line-Outage Distribution Factor analysis) 

is just and reasonable.22 On March 15, 2007, the Commission conditionally accepted 

Midwest ISO’s proposed cost allocation methodology for economic projects to become 

effective April 1, 2007, ensuring that proposed economic projects would have a regional benefit and that the cost of any economic projects would be borne by those 

entities that benefit from the proposed upgrade.23 Just last month, the Commission 

issued a transmission cost allocation order for the PJM Interconnection, LLC which 
87

24PJM Interconnection, L.L.C., 119 FERC Paragraph 61,063 (2007). 25 Cal. Indep. Sys. Operator Corp., 99 FERC Paragraph 61,303 (2002). 26See e.g., Allegheny Energy, Inc., 116 FERC Paragraph 61,058, at P 150 (2006), order on 

reh’g, 118 FERC Paragraph 61,042 (2007) (discussing elements of PJM’s regional transmission 

expansion plan). 27PJM Interconnection, L.L.C., 117 FERC Paragraph 61,218, at P 44 (2006), reh’g pending. 28See e.g., N.Y. Indep. Sys. Operator, Inc., 90 FERC Paragraph 61,319, at p. 62,060 (2000), 

order accepting compliance filing, 95 FERC 61,406 (2001) (noting that NYISO revised its transitional installed capacity (ICAP) market design proposal, among other things, to accommodate 

participation in the ICAP market by resources such as distributed generation). 29See U.S. Dep’t of Energy, The Potential Benefits of Distributed Generation and Rate-Related 

Issues That May Impede Their Expansion: A Study Pursuant to Section 1817 of the Energy Policy Act of 2005 (February 2007), available at http://www.ferc.gov/legal/maj-ord-reg/fedsta/expstudy.pdf. 

allowed the continuation of the existing license plate rate design for existing transmission facilities and approved PJM’s proposal to share the costs of new, centrally 

planned ‘‘backbone’’ transmission facilities—operating at or above 500 kV—on a region-wide basis. At the same time, the Commission directed the parties to develop 

a detailed methodology for determining the beneficiaries for new transmission facilities below 500 kV.24

Distributed Generation 

Distributed generation is primarily a state responsibility, since these generation 

facilities typically interconnect to local distribution facilities subject to state jurisdiction, rather than the interstate power grid. However, the Commission has considered distributed generation in a variety of contexts. Commission staff has participated in various regional initiatives, such as the Mid-Atlantic Distributed Resources 

Initiative (MADRI), which examine a variety of demand response programs, including distributed generation. Distributed generation is important because it can help 

relieve congestion and improve reliability of the bulk power system. 

Over the last several years, the Commission has acted to foster the development 

of distributed generation in a number of specific applications. For example, the 

Commission accepted the California ISO’s proposal to implement a pilot program to 

allow small generating units to aggregate so that they could sell into the ISO’s Supplemental Energy market (known as the Aggregated Distributed Generation Pilot 

Project). In its order, the Commission found that the project, in conjunction with 

streamlined regulatory procedures allowed by the Commission, would benefit customers by facilitating the participation of smaller generators in the wholesale market and also by helping California ISO ensure sufficient resources and increase reliability.25

The Commission has also approved regional transmission planning processes that 

incorporate many bulk power system factors, including distributed generation, thus 

ensuring that these resources are evaluated as part of regional planning.26 In this 

regard, the Commission has asked the PJM RTO to provide additional information 

on advanced technologies currently assessed and to indicate whether distributed 

generation and high efficiency transformers are among those technologies.27 Further, the Commission has permitted distributed generation resources to be considered resources for purposes of capacity markets.28

In addition, the Commission, pursuant to EPAct section 1817, consulted with the 

U.S. Department of Energy on its study of the potential benefits of distributed generation and rate-related issues that may impede their expansion. The results of this 

study were issued in February 2007, and the report is available at http://

www.ferc.gov/legal/maj-ord-reg/fedsta/exp-study.pdf.29 Among other things, the 

study concluded that one key for using distributed generation as a resource option 

for electric utilities is its successful integration with system planning and operation. 

Production of Electricity from Renewable Resources 

The Commission has pursued a number of initiatives in recent years to accommodate the unique characteristics of renewable resources and to ensure that such resources enjoy nondiscriminatory access to the transmission grid. Among the reforms 

to the open access transmission tariff provisions adopted in Order No. 890 was to 

change the pricing of energy and generator imbalances to require such charges to 

be related to the cost of correcting the imbalance in order to encourage efficient 

scheduling behavior and, importantly, to exempt intermittent generators, such as 

wind power producers, from higher imbalance charges. Order No. 890 also created 

a new type of firm point-to-point service (conditional firm) which requires the transmission provider to identify either defined system conditions or an annual number 

of hours during which service will be conditional. This new type of service should 
88

30Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 

72 Fed. Reg. 12,266 (Mar. 15, 2007), FERC Stats. & Regs Paragraph 31,241 (2007), reh’g pending. 

31Standardization of Small Generator Interconnection Agreements and Procedures, Order No. 

2006, 70 FR 34100 (Jun. 13, 2005), FERC Stats. & Regs. Paragraph 31,180 (2005) (Order No. 

2006), order on reh’g, Order No. 2006-A, 70 FR 71760 (Nov. 30, 2005), FERC Stats. & Regs. 

Paragraph 31,196 (2005), order on clarification, Order No. 2006-B, 71 FR 42597 (July 27, 2006) 

FERC Stats. & Regs. Paragraph 31,221. 32 California Independent System Operator Corporation, 119 FERC Paragraph 61,061 (2007) 

be particularly attractive to new generating resources (e.g. intermittent) that are 

seeking project financing.30

The Commission also set forth standardized rule for the interconnection of new 

sources of electricity no larger than 20 megawatts.31 It included standard Small 

Generator Interconnection Procedures (SGIP) and a Small Generator Interconnection Agreement (SGIA) which were designed to reduce interconnection time and 

costs, facilitate development of non-polluting renewable and alternative energy 

sources, and achieve other important goals. The SGIP provides streamlined procedures to evaluate certain interconnection requests. 

Last month, the Commission granted a petition filed by the California ISO seeking approval of a proposal to finance the construction of facilities to interconnect ‘‘location-constrained’’ generating resources to the grid. These are generating resources 

that are constrained as a result of their location, immobility of fuel source, and relative size. These resources typically include renewable forms of generation such as 

wind, geothermal, and solar. In granting the petition, the Commission recognized 

the difficulties faced by generation developers seeking to interconnect these types 

of generation resources. I will elaborate on this recent order in response to your next 

question.32

Question 1. I understand that FERC’s general policy is to allocate the costs of 

building new transmission capacity to the beneficiaries of that new capacity. This 

sometimes is controversial because it is not always easy to determine who benefits 

and who doesn’t. If the costs are primarily borne by the power generation facility—

which needs the lines to get power to the purchaser—then the generation project 

may be cost prohibitive. On the other hand, if the costs of transmission are spread 

more broadly, some customers may be forced to pay to transmit power that they 

don’t consume. Renewable energy generators, which are often located in remote, 

rural areas, have complained that FERC’s determination of the benefits of a transmission line don’t often recognize the benefits a transmission line brings when it 

helps connect renewable energy to the grid. These benefits include reduced greenhouse gas emissions, a more secure domestic energy resource portfolio, and the ability of utilities to meet state renewable portfolio standard requirements. Why doesn’t 

FERC take these benefits into account? If you don’t believe the Federal Power Act 

gives you the authority to recognize all of the benefits of renewable energy, should 

we amend the Federal Power Act? 

Answer. You are correct that the Commission’s general policy is to allocate the 

cost of building new transmission to the beneficiaries of that new capacity. Often 

this results in the costs of new transmission facilities being broadly assigned across 

a large class of beneficiaries, particularly where the transmission addition is a system upgrade providing general system benefits. But for long radial lines that are 

sometimes necessary to connect remote generation to the existing grid, it can result 

in the total costs of the transmission addition being specifically assigned to the new 

generators. As you note, this can be prohibitively expensive for certain renewable 

energy projects which are often located in remote rural areas. However, I believe 

the Commission has sufficient flexibility under its existing rate authorities to take 

into account the benefits associated with renewable generation and to accommodate 

state renewable portfolio standards. 

By way of example, just last month the Commission approved a petition for declaratory order filed by the California ISO to facilitate the interconnection and financing of location-constrained resources to the California ISO grid. The proposal 

was motivated by the potential for the development of significant quantities of location-constrained resources (such as wind, geothermal, and solar) and recognized 

both the growing demand for electricity in California and the requirements of California’s Renewable Energy Portfolio Standard. Specifically, the Commission approved the proposed rate treatment which allows the costs of the interconnection facilities to be initially included in the revenue requirement of the transmission owner 

that constructs the facility and recovered from all users of the CAISO grid through 

its transmission access charge. As new generators interconnect to the line, they 

would be assigned a pro rata share of the going-forward costs of the line. The Commission found that:
89

33See, Regulations for Filing Applications for Permits to Site Interstate Electric Transmission 

Facilities, Order No. 689, 71 Fed. Reg. 69,440 (Dec. 1, 2006), FERC Stats. & Regs. Paragraph 

31,234 (2006) 34See Promoting Transmission Investment Through Pricing Reform, Order No 679, FERC 

Stats. & Regs. Paragraph 31,222 (2006), order on reh’g, Order No 679-A, FERC Stats. & Regs. 

Paragraph 31,236, order on reh’g, 119 FERC Paragraph 61,062 (2007). 35See e.g., American Electric Power Service Corp., 116 FERC Paragraph 61,059 (2006), order 

on reh’g, 118 FERC Paragraph 61,041 (2007); Allegheny Energy, Inc., 116 FERC Paragraph 

61,058 (2006), order on reh’g, 118 FERC Paragraph 61,042 (2007). 

The difficulties faced by generation developers seeking to interconnect location-constrained resources are real, are distinguishable from the circumstances faced by other generation developers, and such impediments 

can thwart the efficient development of needed infrastructure. The CAISO’s 

proposal is consistent with our policies that recognize and accommodate the 

unique circumstances of renewable resources, which are often location-constrained, and it advances state, regional and federal initiatives to encourage 

the development of renewable generation in a manner that satisfies our responsibilities under the Federal Power Act (FPA). 

RESPONSE OF JOSEPH T. KELLIHER TO QUESTION FROM SENATOR THOMAS

Question. Mr. Chairman, we are a little over one and a half years out from the 

date on which President Bush signed the Energy Policy Act of 2005. That legislation 

provided the FERC with a great deal of additional authorities to ensure that our 

energy supply is reliable and affordable. I am especially interested in finding ways 

to move from digging and drilling for coal, oil and gas in my state to the opportunities we have to convert those resources into more valuable commodities. We need 

more electric lines for mine-mouth plants and wind turbines to deliver clean power 

throughout the west. We suffer from a price differential for our oil & gas in Wyoming and need more pipelines to deliver those products. That same infrastructure 

can be used to provide Americans with coal-derived clean diesel fuel. With the new 

authorities provided by the 2005 Energy Policy Act, and the other options available 

to the FERC, how do you believe we can do the best job of ensuring these plans 

for Wyoming, and the west, become a reality? 

Answer. Congress concluded in EPAct 2005 that the status quo was failing to develop the strong transmission grid that our country needs. The Commission’s electric transmission siting authority (new FPA section 216) is limited to projects within 

national interest electric transmission corridors designated by the U.S. Department 

of Energy.33 No such corridors, or draft corridors, have been designated in the Wyoming area. 

Improved transmission planning can also strengthen the grid. The transmission 

grid is regional in nature, essentially operating as a large, regional machine. Transmission planning should reflect the true nature of the grid. A number of cooperative 

western planning processes promise to provide vital pathways for moving Wyoming’s 

power resources west using existing state authorization. The most advanced of these 

is the Frontier Transmission Line. Another opportunity is an initiative by the state 

of Washington to establish an interstate compact with its neighboring states to expedite the siting and construction of interstate transmission facilities as authorized 

under section 216(i) of EPAct 2005. We proposed strengthening regional transmission planning in the final rule reforming our transmission open access rules. 

EPAct 2005 also recognized the need for increased grid investment. To that end, 

the Commission issued a major rulemaking pursuant to the requirements of section 

1241 of EPAct 2005 (new FPA section 219) to establish incentive-based rate treatments associated with new transmission infrastructure investment.34 Since enacting 

the rule, the Commission has granted several requests from utilities for rate incentives for transmission projects that would ensure the reliability of the bulk transmission system or reduce the cost of delivered power to customers by reducing congestion.35

Regarding natural gas, the Commission has acted to strengthen the pipeline network, increase the takeaway capacity from Wyoming, and reduce basis differentials. 

In recent years the Commission has approved a major expansion of the Kern River 

pipeline and the new Cheyenne Plains pipeline that transport a total of about 1.6 

billion cubic feet per day of Wyoming gas to markets outside the state. Recently, 

the Commission approved the Rockies Express West pipeline, one of the largest 

greenfield pipeline projects certificated in recent years. When it commences service, 

Rockies Express will transport more than 1.5 billion cubic feet per day of natural 

gas originating in the Rocky Mountain region, including Wyoming, to supply growing energy demand in markets east of the Rockies. 
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RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR SANDERS

Question 1. It was good to hear you state at the May 10, 2007 hearing on your 

re-nomination that the Federal Energy Regulatory Commission clearly believes that 

one of your important missions is to protect consumers from exploitation by market 

manipulators in both the natural gas and electricity markets. It is my hope that 

consumer protection continues to guide your actions. In that light, I ask that you 

answer the following questions: In January of this year, six of my Senate colleagues 

from New England and I wrote to you, urging that the Commission reconsider its 

order allowing transmission owners in New England to receive an ‘‘adder’’ of 100 

basis points on top of the cost of transmission service in our region. Our letter urged 

FERC to reverse this decision because, after the order was issued, the Commission 

approved a nation-wide rule that required that transmission owners meet a stricter 

‘‘nexus’’ test, in order to receive the incentive, than it applied in the New England 

case. We received your response on February 21, saying that you cannot discuss the 

merits of the case because requests for rehearing of the order are pending at the 

Commission. Can you tell me when a determination on those requests will be made? 

And, hypothetically, do you think it is fair for electric consumers in New England 

to be treated differently, in terms of paying incentive rates, than consumers in the 

rest of the U.S.? 

Answer. I appreciate your continued interest in the Commission’s October 2006 

order on incentive rates for transmission owners in New England. As you correctly 

noted, that matter is pending before the Commission on rehearing and it is under 

active consideration. We have received a number of requests for rehearing in the 

proceeding, and each rehearing request raises its own set of difficult issues for the 

Commission to weigh. I can assure you that the Commission intends to carefully review and thoroughly address all of the issues raised in the rehearing requests as 

expeditiously as possible. 

As to your hypothetical question, the Federal Power Act charges the Commission 

with ensuring that the rates charged by public utilities to all customers, including 

New England customers, are just and reasonable and not unduly discriminatory or 

preferential. In fulfilling this statutory duty, the Commission ascertains whether 

rates of return charged to customers by public utilities are excessive and whether 

rates of return remain within the zone of reasonableness. 

At the same time, rates of return must be sufficient to facilitate needed transmission investment. I would note that all of the regions’ stakeholders and participants have expended great effort to improve New England’s transmission infrastructure and the product thereof is now beginning to be seen. In its 2004 annual report 

on transmission expansion, ISO New England warned that reliability could ‘‘become 

a major system-wide issue for New England in two to four years’’ and that timely 

completion of transmission projects was critical to preserving and improving reliability to resolve local and region-wide reliability problems. 

Since then, major improvements to the regional transmission system have been 

completed including a major 345 kV line in Northwest Vermont. Other projects are 

under construction, and New England is on track to add significant transmission infrastructure in the next 2-3 years, including additional work on the project in Northwest Vermont. The end-result is that though ISO New England projects that another demand record may be set this summer, the region is much better prepared 

to meet that demand than in recent years. 

Question 2. Many of my constituents have expressed concern that the mission of 

ISO-NE says nothing about keeping electricity costs as low as possible for end-use 

consumers. The head of ISO-NE has left the impression with my constituents that 

he regards the mission of the organization to be: 1) ensuring the reliability of the 

regional grid; and 2) making the market mechanisms that have been put in place 

work efficiently. Is it true that the mission of Regional Transmission Organizations 

and Independent System Operators, like ISO-NE, does not include keeping costs as 

low as possible for consumers, while also maintaining reliability? If that is the case, 

why doesn’t FERC insist that their mission statement be modified to include a costeffectiveness goal? 

Answer. I agree with you that a core mission of an RTO or ISO should be to assure that wholesale power prices are just and reasonable, and RTO and ISO market 

rules established by the Commission should prevent market power exercise. Guarding the consumer remains the primary duty of the Commission. Market rules are 

intended to provide consumers with the benefits of a well-functioning market, such 

as just and reasonable prices, continued entry by new generation, improved efficiency, adequate grid investment, and effective demand response. ISO New England 

should be planning to secure these benefits for consumers into the future. It is also 

important that RTOs and ISOs be accountable and have sound governance. The 
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Commission recently held a technical conference on whether RTOs and ISOs are responsive to the needs of their members and other affected stakeholders. We will 

carefully consider all the information received during this conference and evaluate 

whether reforms in this area are necessary. 

Question 3. In ‘‘regulated’’ parts of the U.S. (where states set rates), consumers 

are served by cost-of-service rates. In ‘‘deregulated’’ states where rates are regulated 

by FERC at wholesale, consumers only have access to market-based rates. In the 

12 states that do not have rate caps (as of December 2006) and are therefore fully 

deregulated, the average rate charged to households is 13.4 cents per kilowatt hour48 percent higher than the average rate of 9.1 cents per kilowatt hour in the 38 

regulated states. Is there an explanation for lower rates in cost-of-service states and 

higher rates in regulated states? If so, what is that explanation? Has FERC determined that market-based rates are less than or greater than cost-of-service rates? 

If greater than, does FERC expect the market to produce cost savings sometime 

soon that would reduce costs below cost-of-service rates? If so, when? What conditions must occur to enable competition to reduce costs below cost-of-service rates? 

Answer. Differences in retail rates charged in various states depend on many factors. For example, a region relying extensively on hydropower will have different 

costs than a region largely dependent on fossil fuels, particularly natural gas. Deferrals of cost recovery adopted by state law or regulation also may cause differences. 

Transmission congestion also can affect access to low-price generators. These differences existed even before retail competition was initiated, and states that adopted retail competition generally did so in reaction to high prices produced by traditional cost-of-service regulation. As a recent report noted, ‘‘in 1998, customers in 

New York paid more than two and one-half times the rates paid by customers in 

Kentucky. Rates in California were well over twice the rates in Washington.’’ Report 

to Congress on Competition in Wholesale and Retail Markets for Electric Energy at 

25 and 87, Electric Energy Market Competition Task Force. Untangling the factors 

for differences in retail rates is difficult, and studies seeking to identify the effects 

of competition have reached conflicting results. Market prices vary based on a range 

of conditions, and at different times may be below or above cost-based rates. Market 

prices may be below cost-based prices when electricity supply significantly exceeds 

local needs, but above cost-based prices when additional supplies are needed. 

Competition is national policy in wholesale power markets, but the Commission 

does not rely solely on competition to assure just and reasonable prices. We rely on 

a combination of competition and regulation. In some cases, wholesale competition 

has not worked as envisioned. For example, in some areas, such as California, 

wholesale markets have not been well designed and those flaws have harmed consumers. The proper response is to change the mixture between our reliance on competition and regulation to assure more competitive markets and more effective regulation. We believe the new regulatory tools Congress gave us in EPAct 2005 can 

help improve competition in wholesale power markets. In this regard, the Commission has taken a number of steps over the years to strengthen markets and EPAct 

2005 gave the Commission important new authority to police market manipulation 

and assess civil penalties for misconduct. 

It is important to remember that national policy has evolved over the last 30 

years to support competition for very important reasons. Traditional regulation that 

relies solely on the monopoly provision of electric service can discourage innovation, 

impede entry by more efficient competitors, and increase risks for consumers. The 

three major pieces of energy legislation enacted over the past thirty years (Public 

Utility Regulatory Policies Act of 1978, Energy Policy Act of 1992 and Energy Policy 

Act of 2005) were all designed to counteract these flaws. 

Although competition is national policy, I respect the decisions of states that have 

retained the regulated model for serving retail customers and believe that national 

efforts to increase wholesale competition are fully compatible with varying state 

choices regarding competition or regulation. Whatever the state choice, greater 

wholesale competition can provide better opportunities for load serving entities to 

provide reliable and economic service to their retail customers. 

One of competition’s clear benefits to customers is the shift of risk away from consumers. As an example, many generating units were built in recent years outside 

of cost-based rates and, particularly in the case of natural gas fired generation, the 

investors in those units have suffered the risks of poor investments. In some instances, these risks have led to bankruptcies. In these instances, it is the investor 

who bore the losses, not the consumer. That stands in stark contrast with the nuclear cost overruns of the 1970s and 1980s, which were largely borne by consumers 

and recovered through regulated rates. Other benefits of competition include improvements in nuclear plant operation and construction of more efficient generating 

units. I expect that competition and innovation will only increase in the future, as 
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the Nation demands greater reliance on demand side resources and renewable resources. Vigorous wholesale competition is well suited to facilitate the development 

of these resources. 

Question 4. Does FERC challenge the conclusion by the Energy Information Administration that ‘‘customers in states with competitive retail markets for electricity 

see the effects of natural gas prices in their electricity bills more rapidly than those 

in regulated states, because their prices are determined to a greater extent by the 

marginal cost of energy—the average operating cost of the last, most expensive unit 

run each hour—rather than the average of all plant costs? ‘‘ As natural gas plants, 

with their higher operating costs, often set the hourly marginal price, is this higher 

price ‘‘just and reasonable’’? 

Answer. The effects of higher gas prices may be delayed in states with retail markets that rely on traditional rate regulation. But these effects will be felt, perhaps 

to a greater extent than in competitive retail markets. Under traditional rate regulation, utilities are allowed full recovery of prudent costs, including fuel costs. The 

consumer largely bears the risk of fuel cost rises, not the utility. Some states that 

adopted retail competition froze retail rates for a number of years. In those states, 

most retail customers saw little or no effect from changes in natural gas prices until 

the rate freezes ended. Then they experienced large price increases. In a competitive 

market, if prices are set by the average operating cost of the most expensive unit 

run each hour, customers are paying little or none of the fixed costs of that unit 

(and other units with similar operating costs). Under cost-based regulation, customers generally would bear the fixed costs of these units, even when they are not 

generating. Prices based on the operating costs of natural gas plants can be just and 

reasonable, so long as those units are operating to serve customers and sellers lack 

market power. In a competitive market, market participants bear more risk, which 

can work to the benefit of consumers. The reality is that higher natural gas prices 

are resulting in higher power prices in all regions of the country. 

RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR SMITH

Question 1. Chairman Kelliher, I appreciate your leadership at FERC, and intend 

to support your nomination. I would like you to know that the Oregon PUC is also 

very supportive of you and has sent me a letter to that effect. I do have a few questions for the record, however. As you know, the Commission’s pro forma tariff requires network customers to provide transmission providers with certain information regarding the resources they designate as network resources under their network transmission service agreements. Under the existing tariff, when the resource 

is a particular generating unit, this information includes certain very specific information regarding the unit’s capacity, including such things as unit capacity and normal operating level. For system sales, however, the tariff does not require such unitspecific information, since the sales are not made from a particular generating unit. 

In Order 890, however, the Commission drew a distinction between sales made from 

generating units within a transmission provider’s control area, and system sales 

made from generating units outside of the transmission provider’s control area. The 

Commission maintained the same rule for system sales made from generating units 

outside of the control area, but said that customers may not designate system sales 

as network resources if the sale is sourced from generating units within the control 

area. BPA’s power system is based on hydroelectric power, and a hydroelectric system is operated as one interconnected unit. Because of variability in available water, 

non power constraints, and the multiple uses of the BPA system, BPA cannot and 

does not make power sales from specific generating units. All of its sales are system 

sales. Approximately 100 BPA customers have designated their power purchases 

from BPA as network resources under their network transmission service agreements. Order 890 puts at risk their ability to do so in their post-2011 power sales 

contracts. How does the Commission plan to address this issue, so that BPA can 

continue to make system sales and BPA customers can continue to use network 

transmission service? 

Answer. As I understand this matter, BPA and other Northwest market participants are concerned with the Commission’s pro forma open access transmission tariff provisions relating to designation of network resources and the ability of on-system seller’s choice and system sales agreements to qualify as network resources. 

The Commission’s network resource designation rules were developed to ensure that 

a network customer designating resources provides sufficient information to allow 

the transmission provider to determine the effect of such designation on the transmission provider’s available transfer capability (ATC). ATC represents the transmission capacity available for sale to other market participants and therefore is critical to the functioning of competitive markets. Because on-system seller’s choice and 
93

system sales agreements can significantly obscure the calculation of ATC, they raise 

concerns about planning, efficiency and discrimination. The Commission’s goal in 

Order No. 890 was to encourage more transparent ATC calculation and to avoid inputs that are so vaguely defined that the effects on ATC cannot be determined, 

which would permit the exercise of undue discrimination. As such, in Order No. 890 

the Commission clarified its pro forma tariff provisions relating to the information 

that must be provided when designating network resources; however, the Commission recognized that there may be cause for deviations from the pro forma tariff 

where transmission providers can demonstrate that such deviations are consistent 

with or superior to the pro forma tariff provisions. 

In their requests for rehearing and clarification, BPA and other Northwest market 

participants have raised important points about their reliance on hydroelectric 

power and how the Commission’s clarifications with regard to on-system seller’s 

choice and system sales will affect them. These requests include a good deal of additional detail, which the Commission currently is carefully considering. In addition, 

since the Commission’s ex parte prohibitions do not apply to rulemakings, Commission staff has invited BPA and others to discuss their specific concerns in advance 

of a Commission order on rehearing of Order No. 890. I can assure you we will carefully consider the arguments of these parties and their specific circumstances. 

Question 2. Entities in the region have some concern that certain interpretations 

of the new OATT rules will cause the pre-schedule and real-time markets in the NW 

to evaporate. If a particular set of rules would have an adverse impact on the reliability or cost of electric service in a given region, how would you work with that 

region to identify mutually acceptable ways to go forward? Would you agree to defer 

action on the rules until this occurs? 

Answer. This concern appears to relate to the pro forma tariff provision, adopted 

in Order No. 890, adopting a minimum lead-time for undesignating network resources to make firm third-party power sales. Order No. 890-established that minimum-lead time to mirror the deadline for scheduling firm point-to-point transmission service adopted in Order No. 888. As the Commission adopted a minimum 

undesignation lead time in Order No. 890 to coincide with the existing scheduling 

deadline for point-to-point transmission in the pro forma tariff established in Order 

No. 888, it did not expect any significant effect on any market, as most parties use 

firm point-to-point service to transmit firm third-party power sales. Moreover, under 

Order No. 888, the scheduling deadline provision of the pro forma tariff specifically 

contemplated regional variations that reflect ‘‘a reasonable time that is generally accepted in the region and is consistently adhered to by the transmission provider.’’ 

In addition, the Commission in Order No. 890 made clear that transmission providers with existing approved deviations from the pro forma tariff that were not 

changed in Order No. 890 would be allowed to retain such variations. Accordingly, 

if a transmission provider had a firm point-to-point scheduling deadline variation 

from the pro forma tariff, then that deadline would also apply to its undesignations. 

Order No. 890 made clear that any transmission providers that desired a deviation 

from the pro forma tariff are free to submit them to the Commission pursuant to 

section 205 of the FPA. 

In response to your more general question, the Commission currently is evaluating requests for rehearing and clarification of Order No. 890, including a number 

of requests that address the issues raised in your question. In addition, the Commission has received a request to convene a technical conference with Commission staff 

to discuss the effects on Western utilities of the minimum lead-time for 

undesignating network resources. The Commission is carefully evaluating these requests to assess the impact of its rules on the region. 

Question 3. The Northwest is unlikely to form an RTO any time in the near future. This situation has the potential to adversely affect those investor-owned, jurisdictional entities that you regulate. How will you adopt and enforce rules to address 

this situation and to recognize and respect the mixed ownership of transmission infrastructure across federal government, publicly-owned utilities, and private utilities 

that we have in the Northwest? 

Answer. I recognize the long history of coordination of market participants in the 

Northwest and the region’s support of voluntary participation by public utilities and 

non-public utilities in supporting regional initiatives. The Commission recently approved the ColumbiaGrid Planning Agreement to coordinate members’ efforts to create a single, regional planning process for both public utility and non-public utility 
94

36 ColumbiaGrid, a non-profit corporation formed in March 2006, filed the proposed Planning 

Agreement on behalf of Washington State-based Avista Corp. and Puget Sound Energy Inc., 

which are Commission-jurisdictional utilities. In addition to Avista and Puget, ColumbiaGrid’s 

members include: the Bonneville Power Administration; Public Utility District No. 1 of Chelan 

County, Washington; Public Utility District No. 2 of Grant County, Washington; the Public Utility District No. 1 of Snohomish County, Washington; Seattle City Light; and Tacoma Power. 37The members of Northern Tier include PacifiCorp, Idaho Power, Northwestern Energy, 

Utah Associated Municipal Power Systems, and Deseret Power. 38 E.g., United States Department of Energy—Bonneville Power Administration, 80 

FERCParagraph 61,118 at 61,369 (1997); United States Department of Energy—Bonneville 

Power Administration, 67 FERC Paragraph 61,351 at 62,217, order granting reh’g on other 

grounds, 68 FERC Paragraph 61,344 (1994). 39 16 U.S.C. §§ 839e(a)(2), (k) (2000). 

transmission providers.36 In its order, the Commission approved the planning agreement without asserting jurisdiction over ColumbiaGrid for the planning activities 

which it would undertake. Furthermore, in addressing issues raised by parties in 

the proceeding, the Commission noted that further coordination with other sub-regions in the Western Electricity Coordinating Council may be necessary. These are 

among the issues that will be discussed during the upcoming Commission staff technical conference that was required by our recent Order No. 890 revising the openaccess transmission tariff. These issues will also be addressed in the subsequent 

Order No. 890 compliance filings. In addition, Commissioners and staff have met 

on numerous occasions with, and sent staff to planning meetings with, the sponsors 

of the Northern Tier transmission group. This group is also comprised of public and 

nonpublic utilities, and they are collaboratively working on regional transmission 

planning and operational coordination initiatives.37

I believe that coordinated planning will provide for increased transmission grid 

reliability, operational efficiency, and more rationally economic transmission expansions which will benefit the Pacific Northwest region. 

I also support the other voluntary initiatives undertaken by entities in the Northwest to better coordinate their resources, such as the recent initiative to better coordinate their efforts in resolving ‘‘area control errors’’ in order to minimize the adverse impacts on neighboring utility systems that result from the momentary imbalances between electricity generation and demand. The coordination between systems 

in resolving these imbalances results in more efficient use of both generation and 

transmission resources for the region, and it better accommodates the use of intermittent, renewable generation resources such as wind. 

RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR CANTWELL

Question 1a. This year the administration’s budget is seeking to raise rates on the 

ratepayers of the Bonneville Power Administration (BPA) by taking away revenue 

from power produced by the region. Under the Northwest Power Act, FERC has the 

final say in approving the Bonneville Power Administration’s rates provided that 

the proposed rates are ‘‘sufficient to assure repayment of the Federal investment in 

the Federal Columbia River Power System over a reasonable number of years after 

first meeting the Administrator’s other costs... and are based upon the Administrator’s total system costs.’’

How would you interpret the definition of terms like ‘‘reasonable number of years’’ 

and other terms in BPA’s various organic statutes what deference would you give 

to years of agency precedent and practice in defining those terms? 

Answer. Under section 7(a)(2) of the Pacific Northwest Electric Power Planning 

and Conservation Act, 16 U.S.C. § 839e(a)(2) (2000), the Commission is charged with 

confirming and approving BPA’s rates upon a finding by the Commission that such 

rates are, among other things, sufficient to assure repayment of the federal investment in the Federal Columbia River Power System ‘‘over a reasonable number of 

years’’ after first meeting BPA’s other costs. The Commission has traditionally considered the repayment period, i.e., the ‘‘reasonable number of years,’’ as 50 years, 

although the Commission has also explained that there should be some reasonable 

intermediate level of repayment to ensure that repayment will, in fact, occur by the 

end of the fiftieth year.38 I would give significant deference to agency precedent and 

practice in this area. 

Question 1b. What deference would you give to federal statues that define certain 

provisions in BPA’s organic statutes? 

Answer. I recognize the legal limits of our jurisdiction over BPA. The Commission’s authority to review BPA’s rates, and the criteria by which those rates are to 

be judged, are spelled out in the Pacific Northwest Electric Power Planning and 

Conservation Act (Northwest Power Act), particularly sections 7(a)(2) and 7(k).39 In 
95

40 United States Department of Energy—Bonneville Power Administration, 80 FERC Paragraph 61,118 at 61,368-69 (1997) (footnotes omitted). 41See, e.g., United States Department of Energy—Bonneville Power Administration, 80 FERC 

Paragraph 61,118 at 61,369-70, nn.7, 9 (1997); United States Department of Energy—Bonneville 

Power Administration, 67 FERC Paragraph 61,351 at 62,217 nn.10, 12, order granting reh’g on 

other grounds, 68 FERC Paragraph 61,344 (1994); United States Department of Energy—Bonneville Power Administration, 54 FERC Paragraph 61,235 at 61,691 nn.20, 25 (1991). 

describing the nature and scope of the Commission’s review, the Commission has 

explained that its review is limited and is appellate in nature: 

The Commission’s review of Bonneville’s regional power and transmission rates is 

limited to determining whether Bonneville’s proposed rates meet the three specific 

requirements of section 7(a)(2):

(A) they must be sufficient to assure repayment of the federal investment in 

the Federal Columbia River Power System over a reasonable number of years 

after first meeting the Administrator’s other costs, 

(B) they must be based upon the Administrator’s total system costs, and 

(C) insofar as transmission rates are concerned, they must equitably allocate 

the costs of the federal transmission system between federal and non-federal 

uses of the system.

Commission review of Bonneville’s non-regional, nonfirm rates is also limited. Review is restricted to determining whether such rates meet the requirements of section 7(k) of the Northwest Power Act, which requires that they comply with the 

Bonneville Project Act, the Flood Control Act of 1944, and the Federal Columbia 

River Transmission System Act. Taken together, those statutes require Bonneville 

to design its non-regional, nonfirm rates:

(A) to recover the cost of generation and transmission of such electric energy, including the amortization of investments in the power projects within a reasonable 

period, 

(B) to encourage the most widespread use of Bonneville power, and 

(C) to provide the lowest possible rates to consumers consistent with sound business principles.

Unlike our statutory authority under the Federal Power Act, the Commission’s 

authority under sections 7(a) and (k) of the Northwest Power Act does not include 

the power to modify the rates. The responsibility for developing rates in the first 

instance lies with Bonneville’s Administrator. The rates are then submitted to the 

Commission for approval or disapproval. In this regard, the Commission’s role can 

be viewed as appellate: to affirm or remand the rates submitted to us for review.40

Question 1c. As a FERC Commissioner, how would you rely on relevant judicial 

precedent in order to define terms in BPA’s organic statutes? 

Answer. I would fully respect all applicable judicial precedent. I also note that the 

Commission, in exercising its responsibilities under the Northwest Power Act, has 

long been guided by judicial precedent interpreting that Act. For example, in describing the scope of its review, the Commission traditionally has pointed to the 

Ninth Circuit Court of Appeals decisions in Aluminum Company of America v. Bonneville Power Administration, 903 F.2d 585 (9th Cir. 1990), and Central Lincoln 

Peoples’ Utility District v. Johnson, 735 F.2d 1101 (9th Cir. 1984).41

Question 2. As you probably know, you will have a number of applications for renewal of hydroelectric licenses before you in the next few years. The Northwest is 

heavily reliant on hydroelectric generating resources. In Washington State alone, 

some 13 projects representing 5,863 MW of generating capacity will be in various 

stages of the relicensing process between now and 2015. Can you provide the Committee with your perspective on hydroelectric power and your thoughts on the relicensing process under EPAct 2005? 

Answer. The Commission regulates over 1,600 hydroelectric projects at over 2,500 

dams pursuant to Part I of the Federal Power Act (FPA). Together, these projects 

represent 57 gigawatts of hydroelectric capacity, more than half of all the hydropower in the United States, and over five percent of all electric generating capacity 

in the United States. Hydropower is an essential part of the Nation’s energy mix 

and offers the benefits of an emission-free, renewable, domestic energy source with 

public and private capacity together totaling about ten percent of U.S. capacity. Hydropower also supports efficient, competitive electric markets by providing low-cost 

energy reserves and ancillary services. Hydropower projects provide other public 

benefits such as increased water supply, recreation, economic development, and 

flood control, while minimizing adverse impacts on environmental resources. 
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In processing hydropower applications under the FPA, the Commission conducts 

an extensive and transparent collaborative pre-filing process, during which it receives input from a multitude of stakeholders, including citizen groups, environmental organizations, tribal interests, and local, state, and federal resource agencies. The Commission’s goal in licensing is to establish an efficient, predictable, and 

timely licensing process that develops a record sufficient for the Commission to take 

final action and to license projects that are best adapted to the comprehensive development of our Nation’s waterways. To achieve these goals, Commission staff is fully 

engaged in the pre-filing portion of the process, to help stakeholders define the scope 

of the licensing process along with the type and number of studies that are undertaken. This early pre-filing involvement by Commission staff will enable expeditious 

Commission action on the application after it is filed. 

Section 241 of EPAct 2005, among other things, (1) amended sections 4(e) and 18 

of the FPA to provide that any party to a license proceeding is entitled to a determination on the record, after opportunity for a Department trial-type hearing of any 

disputed issues of material fact with respect to any Department’s mandatory conditions or fishway prescriptions and (2) added a new section 33 to the FPA that allows 

the license applicant or any other party to the license proceeding to propose an alternative condition or fishway prescription. Our experience indicates that EPAct 

2005 continues to provide an increased incentive for the Departments of the Interior, Commerce, and Agriculture to provide cost-effective and factually-supported 

mandatory conditions and has encouraged greater interaction between the Departments and license applicants in the development of environmental measures. EPAct 

2005 has added a degree of accountability that previously did not exist, and the Departments continue to make a laudable effort to comply with Congress’ mandate. 

A second important aspect of EPAct 2005 is section 1301, which provides for renewable energy tax credits for incremental energy gains from efficiency improvements or capacity additions to existing hydroelectric facilities placed into service 

after August 8, 2005, and before January 1, 2008. Subsequent legislation extended 

the January 1, 2008 date to January 1, 2009. Under that section, the Commission 

certifies the ‘‘historic average annual hydropower production’’ and the ‘‘percentage 

of average annual hydropower production at the facility attributable to the efficiency 

improvements or additions of capacity’’ placed in service after August 8, 2005, and 

before January 1, 2009. 

We have issued a guidance document to help our licensees seeking tax credit certification. The document, which is posted on our web site (http://www.ferc.gov/

industries/hydropower.asp) explains what information our licensees need to provide 

for our review and evaluation to certify incremental energy gain. We have also disseminated information about the tax credit at national conferences throughout the 

country, to encourage efficiency upgrades. 

These efforts have resulted in licensees initiating evaluation of possible upgrades 

at their projects. To date, the Commission has issued 11 orders certifying incremental energy gains for a total of about 126,390 megawatt-hours. 

Question 3a. As you know, western energy markets and ratepayers in WA State 

are still suffering negative effects of deregulation and related market manipulation 

during the 2000-2001 energy crisis. Ratepayers in the Northwest and the larger regional economy continue to suffer the ill effects of related energy hikes—some as 

high as 50%. The GAO noted in a November 2005 report that ‘‘. . . consumers in 

California and across other parts of the West will attest, there have been many negative effects [related to restructuring], including higher prices and market manipulation.’’

Has energy market restructuring been successful? 

Answer. I believe wholesale competition has benefited customers in many ways, 

but I also acknowledge there have been problems and improvements are still needed. I am well aware of the harm from the California and Western electricity crisis 

and the Commission has worked for many years to strengthen wholesale markets 

to avoid a recurrence of market dysfunction. In addition, our new authorities under 

EPAct, particularly to prevent market manipulation and impose civil penalties for 

market abuse, improve our ability to strengthen competition and provide effective 

regulation. 

The problems stemming from the California electricity crisis should not, however, 

obscure the benefits that wholesale competition can provide to consumers. Particularly in the Northwest, where there are many smaller sellers and purchasers, wholesale trade is critical to providing load serving entities the opportunity to minimize 

their cost of serving retail load. Competition can also provide strong incentives for 

developers to construct new generation, including renewable energy necessary to 

meet renewable portfolio standards. 
97

42Public Utility Dist. No. 1 of Snohomish County, Wash., v. FERC, No. 03-74208 (9th Cir. December 19, 2006), and California Public Utils. Comm’n v. FERC, No. 03-74207 (9th Cir. December 19, 2006). 

I can assure you we will remain vigilant in overseeing markets in every region 

to ensure that they are working to benefit consumers. We have adopted many reforms in this area, including Order No. 890, to strengthen open access to the grid. 

We also have undertaken a generic review of competition in wholesale markets to 

identify any necessary improvements in regional markets. 

The Commission has held two technical conferences this year on ways to enhance 

competition in organized markets. Demand response and long-term contracting have 

been two of the main issues, and both of these can help alleviate price volatility and 

price levels. Another topic has been ways to improve the responsiveness of RTOs 

and ISOs. The Commission is considering the suggestions made at the conferences, 

with the goal of taking action soon. I have not yet decided which specific steps 

should be implemented. 

Question 3b. How should FERC treat those areas of the country that have not restructured and have not deregulated retail rates, like the Pacific Northwest? Do you 

believe those regions should largely be left alone to address the needs of their specific industry structure as they see fit? If not, how far should FERC go in changing 

them? 

Answer. Regional differences on market structure are entirely appropriate and 

consistent with our responsibilities under the Federal Power Act. Shortly after I became Chairman, the Commission terminated the Standard Market Design proposal, 

which did not recognize regional differences in wholesale market structure. I recognize that wholesale markets in this country are regional in nature, and there are 

significant differences among the regions. There are different competitive wholesale 

market structures, and I expect those differences to remain for some time. I see no 

reason to believe the bilateral market structure in the Pacific Northwest is less competitive than the organized markets in other regions, and see no reason to favor one 

market structure over another. I believe the different wholesale market structures 

can be equally competitive. The Commission’s goal is to enhance competition under 

whatever structure is used in a region, not mandate the use of one structure instead 

of others. For example, the Commission recently updated and strengthened its open 

access transmission tariff (Order No. 890), which is used in traditional, bilateral 

markets. In doing so, the Commission adopted approaches on imbalance penalties 

and ‘‘conditional firm service’’ developed by Bonneville. These approaches can enhance competition in the bilateral markets of the Pacific Northwest, without requiring a shift to a different market structure. 

Question 4. During debate on the Energy Policy Act of 2005, I opposed the effort 

by some legislators to raise the standard for contract modifications from the ‘‘just 

and reasonable’’ standard to the ‘‘public interest’’ standard. I understand that, at 

one time, the Commission was considering adoption of a rule that would, effectively, 

make the ‘‘public interest’’ standard the default for contract modifications. Is this 

docket still alive at FERC or has it been terminated? Do you agree that tariff provisions—whether they are arrived at through settlement agreement or other means—

can be challenged under the ‘‘just and reasonable’’ standard? 

Answer. The Commission’s Notice of Proposed Rulemaking regarding Mobile-Si- erra issues proposed to clarify ambiguities in the law, thereby providing customers 

and sellers greater certainty regarding how their contracts would be treated by the 

Commission. The central issue addressed in the proposed rule was the interpretation of contracts that are not clear on whether the parties wish to be bound by the 

just and reasonable standard or, alternatively, the public interest standard. The 

Commission proposed that, in the narrow situation where the parties failed to express their intent on this issue, the public interest standard should apply. The U.S. 

Court of Appeals for the Ninth Circuit recently adopted that position.42 Given these 

decisions, it may no longer be necessary for the Commission to issue a final rule 

on this issue. Nevertheless, the docket has not been terminated. 

I do agree that, in many situations, the just and reasonable standard will apply 

to Commission review of jurisdictional contracts. For example, the just and reasonable standard will apply any time the parties agree to that standard in drafting 

their contracts. As a general matter, the just and reasonable standard also will 

apply to transmission or transportation contracts provided entered into under Commission-approved open access tariffs. 

It is also important to emphasize that the Commission has refused, and will continue to refuse, to be bound to the public interest standard where such standard 

is not appropriate. For example, the Commission has declined to be bound by the 

public interest standard when the parties seek to apply the just and reasonable 
98

43Southern Company Services, 60 FERC Paragraph 61,273 (1992), order denying reh’g, 67 

FERC Paragraph 61,080, at 61,227-28 (1994), citing Papago Tribal Utility Authority v. FERC, 

723 F.2d 950 (D.C. Cir. 1983); Southern Company Services, 119 FERC Paragraph 61,065 at P 

42 (2007). 44Maine Public Utilities Commission v. FERC, No. 05-1001 (D.C. Cir. June 30, 2006). 45 Northeast Utilities Service Co., 55 F.3d 686, 690 (1st Cir. 1995); Texaco Inc. v. FERC, 148 

F.3d 1091, 1096 (D.C. Cir. 1998). 

standard to themselves.43 The Commission has declined to be bound by the public 

interest standard when transmission owners have entered into agreements that significantly impact third parties or the marketplace as a whole.44 The Commission 

also has declined to be bound where generators and an ISO or RTO have entered 

into must-run contracts that significantly impact third parties. 

Finally, even when the Commission agrees to be bound to the public interest 

standard, I do not believe that standard is practically insurmountable. The Commission has reformed contracts under the public interest standard and been upheld by 

the courts.45 Moreover, contract reform under the public interest test is not limited 

to the three criteria in the original Mobile and Sierra decisions—where the existing 

rate structure might impair the financial ability of the public utility to continue its 

service, cast upon other consumers an excessive burden, or be unduly discriminatory. We will, in all cases, continue to fulfill our obligations under the Federal 

Power Act and Natural Gas Act to protect customers from exploitation by sellers of 

electricity or natural gas. 

Question 5. Congress carefully crafted the ‘‘FERC-Lite’’ provisions of the Energy 

Policy Act of 2005. Can you please provide the Committee with your interpretation 

of this provision and the extent of the Commission’s jurisdictional reach over the 

Bonneville Power Administration? 

Answer. New section 211A of the FPA, with certain exceptions, allows the Commission, by rule or order, to require an ‘‘unregulated transmitting utility’’ to provide 

transmission services ‘‘(1) at rates that are comparable to those that the unregulated transmitting utility charges itself; and (2) on terms and conditions (not relating to rates) that are comparable to those under which the unregulated transmitting 

utility provides transmission services to itself and that are not unduly discriminatory or preferential.’’ An unregulated transmitting utility is defined as an entity 

that: (1) owns or operates facilities used for the transmission of electric energy in 

interstate commerce; and (2) is an entity described in FPA section 2010. Section 

201(f), in turn, provides among other things, that, nothing in Part II of the FPA 

shall apply to or be deemed to include the United States, a state or any political 

subdivision of a state, certain electric cooperatives, or any agency, authority or instrumentality of any one or more of the foregoing, or any corporation which is wholly owned, directly or indirectly, by any one or more of the foregoing, unless such 

provision makes specific reference thereto. 

Because BPA operates facilities used for the transmission of electric energy in 

interstate commerce and, as an authority or instrumentality of the United States, 

is an entity described in FPA section 201(f), arguably the Commission would have 

authority to order BPA to provide transmission services under new section 211A. 

However, the Commission has not exercised its authority under section 211A and 

thus at this time has not interpreted the scope of its applicability or the extent of 

the Commission’s jurisdictional reach over BPA under section 211A. I would note 

that in the Commission’s recent rulemaking to reform open access transmission requirements for public utilities (final rule issued Feb. 16, 2007), the Commission declined to exercise its authority under new section 211A on a generic basis, stating 

that it would be more appropriate to consider the use of new section 211A on a caseby-case basis if an aggrieved customer believes it has been denied comparable service. The Commission in Order No. 890, however, retained its existing ‘‘reciprocity’’ 

provision for non-jurisdictional utilities. Under that provision, a non-jurisdictional 

utility such as BPA is required to provide comparable transmission access to any 

public utility from whom it takes transmission service, and a non-jurisdictional utility may voluntarily file a ‘‘safe harbor’’ tariff with the Commission. BPA has such 

a safe harbor tariff and therefore customers of the BPA system currently receive 

comparable transmission access pursuant to the terms of that tariff. 

Question 6. I am encouraged that on April 6, 2007 the Commission approved 

ColumbiaGrid as a formal regional transmission planning program for the Pacific 

Northwest that will not be considered a jurisdictional regional transmission organization (RTO). Despite some indications to the contrary, the Commission has said repeatedly that RTOs are voluntary and that each region should be able to decide 

what type of transmission planning system is best for its circumstance. As you 

know, a majority of stakeholders in the Northwest have long opposed a FERC-regu-
99

46 ColumbiaGrid, a non-profit corporation formed in March 2006, filed the proposed Planning 

Agreement on behalf of Washington State-based Avista Corp. and Puget Sound Energy Inc., 

which are Commission-jurisdictional utilities. In addition to Avista and Puget, ColumbiaGrid’s 

members include: the Bonneville Power Administration; Public Utility District No. 1 of Chelan 

County, Washington; Public Utility District No. 2 of Grant County, Washington; the Public Utility District No. 1 of Snohomish County, Washington; Seattle City Light; and Tacoma Power. 

lated RTO and have decided that a voluntary organization of public and private 

transmission owners and the Bonneville Power Administration (BPA), like 

ColumbiaGrid, is most suitable. This organizational approach was intentionally pursued to avoid the problems associated with ‘‘organized markets’’ and avoid expansion of FERC jurisdiction. Mr. Chairman, can you confirm that the Commission’s 

position is that RTOs are, in fact, voluntary and that the Commission has no intention of mandating, either directly or through indirect orders, an RTO or market 

mechanisms on the Northwest? Can you please provide your views on 

ColumbiaGrid? 

Answer. I can confirm that it is my position that RTO participation is voluntary, 

and that I have no intention of mandating, either directly or indirectly, an RTO or 

market mechanisms on the Northwest. I believe that this is also the view of the current Commission. Again, shortly after I become Chairman, the Commission issued 

an order terminating the Standard Market Design proposal, which would have made 

participation in an RTO effectively mandatory. As I stated when the Commission 

issued its proposed rule on open access transmission reform, ‘‘We continue to support voluntary RTO formation’’ and ‘‘our proposed rules do not push utilities into 

RTOs.’’

Regarding the ColumbiaGrid initiative, one of my top priorities with respect to 

Western electricity issues is to foster the continued history of regional cooperation 

among parties in the Pacific Northwest. The Commission recently approved the regional transmission planning proposal submitted by ColumbiaGrid which I believe 

should strengthen regional grid planning in the Pacific Northwest. The increased coordination and transparency contemplated by the Planning Agreement can potentially improve reliability, operational efficiency and expansion of the transmission 

grid. The proposal was approved without asserting Commission jurisdiction over 

ColumbiaGrid for purposes of conducting activities under the Planning Agreement. 

I believe the Commission’s approval of the ColumbiaGrid regional transmission 

planning process clearly indicates that the Commission has no intention of mandating an RTO or other market mechanisms in the Pacific Northwest.46

Question 7. The recent EPAct required inter-agency report on competition cast 

doubt on the competitiveness of wholesale electricity markets. Would you agree that 

if wholesale markets are not demonstrably subject to effective competition, then 

market rates cannot be ‘‘just and reasonable’’? 

Answer. Yes, the Federal Power Act requires the Commission to ensure that 

wholesale rates are just and reasonable. If, for example, a jurisdictional wholesale 

seller has market power, the Commission must mitigate that market power to ensure just and reasonable rates, by imposing cost-based rates or other forms of mitigation. 

Question 8. What specific steps does the Commission undertake to assure the existence of competitive markets before approving market-based rates? 

Answer. Any public utility that seeks authority to sell electric energy at marketbased rates must demonstrate that it lacks or has mitigated market power in transmission and generation, that it cannot erect other barriers to entry, and that there 

is no affiliate abuse or reciprocal dealing. It also must obtain separate approval if 

it seeks to sell power to an affiliate. Applications to sell at market-based rates are 

publicly noticed, with opportunity for intervention and protest. Under current Commission policy, the Commission has two market power screens and, if an applicant 

fails either one, it will be presumed to have market power; it must then file a more 

in-depth market power analysis, propose mitigation, or be denied (or lose) marketbased rate authority. Depending upon the record, the Commission may grant market-based rates in some geographic areas, but deny it in others where markets are 

not competitive. 

Applicants that receive authority to sell at market-based rates must file electronic 

quarterly reports for all transactions, triennial market power analysis updates, and 

change of status notifications if there is any change in facts relied upon in the Commission’s market power evaluation. In addition to the Commission’s market power 

evaluation of individual sellers, if a seller is transacting in real-time or day-ahead 

markets administered by ISOs or RTOs, it must comply with the market rules approved by the Commission for a particular ISO/RTO, including rules designed to 

mitigate market power and any bid caps that have been approved, and it is subject 
100

to oversight by both the market monitor of the ISO/RTO and the Commission’s enforcement office. The Commission may require a utility-specific market power analysis update at any time and all sellers are subject to the Commission’s anti-manipulation rules pursuant to new authority granted in EPAct 2005. 

I note that the Commission recently issued a final rule to strengthen its open access transmission requirements to mitigate market power in transmission. In addition, the Commission has underway a rulemaking to codify the more rigorous market power analysis requirements it has applied in individual cases in recent years, 

including the generation market power screens discussed above. The Commission is 

also proposing to adopt a regional approach to reviewing market-based applications 

and triennial updates (i.e., all sellers in a region would be reviewed at the same 

time). The Commission has also proposed to revoke its regulation adopted in 1996 

which relieves a utility from having to demonstrate a lack of market power in generation with respect to sales from capacity constructed on or after July 9, 1996. We 

hope to finalize this rulemaking soon. 

Question 9. Despite significant concerns raised by myself and others in Congress, 

as well as stakeholders in the region, FERC approved the California ISO’s Market 

Redesign and Technology Upgrade (MRTU) plan last year. Our region is still recovering from the crisis of 2000-2001 and many thought that FERC waited too long 

to respond to the California market failure. Our region does not want to relive that 

experience. While we will hope for the best, does the Commission have a plan in 

place to address any unanticipated market meltdown from the MRTU Day 2 market 

structure to avoid the kind of crisis we experienced in 2000-2001? 

Answer. Since the 2000-2001 energy crisis occurred, the Commission has taken 

several actions to prevent a reoccurrence, including eliminating a requirement that 

all load be bid into the California Power Exchange and instituting a Must Offer Obligation to ensure that generation could not be withheld from the market place 

when needed for reliability. 

While these changes have helped prevent additional energy crises in the intervening years, there still remain fundamental market design issues that the MRTU 

tariff is designed to fix. Specifically, the MRTU market design addresses three key 

factors that are still present and contributed to the 2000-2001 energy crisis: (1) the 

lack of adequate electricity supply, (2) flawed market rules, and (3) market manipulation. The MRTU tariff, as modified by the Commission, provides for a new congestion management system, adopts a more accurate model of the grid, revises market 

power mitigation measures, and establishes a forward energy market. The MRTU 

tariff builds upon the resource adequacy reforms adopted by the state of California 

to ensure that all load serving entities procure adequate generation capacity to 

serve their load. MRTU retains bid caps on energy markets to ensure that prices 

remain just and reasonable and, paired with a resource adequacy requirement, 

lessens the likelihood of price spikes due to shortages. By establishing a day-ahead 

energy market, MRTU will increase the transparency of energy prices, which in 

turn allows the California ISO and the Commission to better detect attempts at manipulation. The day-ahead market will provide market efficiencies that will help 

keep wholesale electricity prices down and make it easier for the California ISO to 

maintain reliability. 

We have also committed to a sound and orderly implementation plan for the 

MRTU tariff. The MRTU tariff will be implemented only when the California ISO’s 

and the market participants’ systems, software and tools have been fully tested and 

the California ISO and its stakeholders are confident that MRTU will function properly when implemented. Accordingly, we are requiring the California ISO to file a 

readiness certificate with the Commission sixty days prior to the implementation of 

the MRTU. The California ISO will satisfy market participants’ readiness through 

a process that includes completion of training in the new markets and participation 

in market simulation exercises. 

Finally, the Commission in its unanimous approval of the MRTU tariff looked 

closely at ‘‘seams’’ issues and concerns raised by parties located throughout the 

Western Interconnect. Furthermore, the Commission held a technical conference in 

Phoenix, Arizona in December 2006 that provided parties an opportunity to identify 

and discuss solutions to resolve alleged MRTU seams issues between the California 

ISO and existing neighboring systems. Because of our interest in better understanding the Northwest perspective on these issues, we invited several representatives from this region to appear as panelists at this conference, including those representing public power utilities, investor-owned utilities, independent power producers, and Bonneville. The Western Electric Coordinating Council (WECC) noted 

in its post-technical conference comments that ‘‘no reliability or seams issues requiring resolution prior to MRTU implementation were identified . . .’’. Participants 

further recognized that seams issues existed in the West prior to MRTU and were 
101

47Loop flows are affected by a combination of factors, including energy trading patterns, generation additions and retirements, generation dispatch, load levels, and transmission line additions and outages, most of which are not affected by MRTU implementation. 

not created by MRTU. Thus, while the Western interconnect still has issues such 

as loop flows,47 the Commission has concluded that the resolution of most seams 

issues should be considered and addressed in a comprehensive, West-wide context. 

The Commission has directed the CAISO and neighboring control areas to meet as 

needed to resolve seams between them, and to jointly report on the progress of these 

efforts in quarterly status reports to the Commission. The resolution of seams in the 

West is thus an on-going process that began prior to MRTU and is continuing. I 

am encouraged by market participants’ commitment to resolve these issues collaboratively, and the Commission has and will assist them in this process when necessary. 

Question 10. I am concerned that our nation’s electricity grid is based on outmoded technology that makes it less reliable and requires greater generation resources than it should. I have been working with a broad group of stakeholders to 

develop comprehensive legislation that will streamline and create greater efficiencies to our electricity grid. Chairman Kelliher, what can FERC do to develop 

standards for appliance interfaces, equipment interoperability, and system-to-system 

data sharing to facilitate improved grid reliability and operability through technologies like smart metering and net metering? Can you provide details on previous 

and ongoing FERC efforts in this area? 

Answer. While the Federal Power Act gives the Commission no direct jurisdiction 

over matters such as appliance standards and equipment interoperability, the Commission staff pays close attention to developments in this area. We do so to ensure 

that our policies dovetail, to the extent practicable, with those of the states and regions where such policies are being implemented. On issues such as grid reliability 

and operations, the Commission does have jurisdiction and has taken numerous 

steps pursuant to its existing authority and new authority given the Commission 

under EPAct 2005 to implement regulations in these areas. 

As a general matter, the Commission can aid the development of new technologies 

by fostering transparency of wholesale market information (e.g., prices, transmission 

congestion, transfer limits), requiring system-to-system sharing of certain data 

where appropriate, educating through its orders and required reports, and as appropriate ensuring cost recovery of such technologies. 

Since passage of the Energy Policy Act of 2005 (EPAct 2005), the Commission has 

taken the initiative on several fronts to foster advanced technology. 

In August 2006, the Commission published a Commission staff report, Assessment 

of Demand Response and Advanced Metering. In addition to assessing demand response, this report analyzed the current state-of-the-art in advanced metering, and 

calculated an estimate of the penetration of advanced metering by region and state. 

The August 2006 report also indicated the need for interoperability standards. Commission staff plans to continue to monitor and assess advanced metering in future 

annual reports. 

On February 15, 2007, the Commission issued Order No. 890 to reform Open Access Transmission Tariffs. One of the reforms included in Order No. 890 are new 

requirements on open transmission planning processes. Each jurisdictional transmission provider’s planning process must meet nine specified planning principles: 

coordination; openness; transparency; information exchange; comparability; dispute 

resolution; regional coordination; economic planning studies and cost allocation. 

Compliance with this order by transmission providers should provide support for 

standardized approaches to a modern transmission grid. 

On March 16, 2007, the Commission issued Order No. 693 that accepted and directed modifications to mandatory reliability standards. Several of the mandatory 

standards address data sharing about interchange transactions and required documentation on demand forecasts and demand-side management. 

Currently, there are two NERC standards that deal with telecommunication and 

communications and coordination, COM—001 and COM—002. COM—001 requires 

each Reliability Coordinator, Transmission Operator and Balancing Authority to 

provide adequate and reliable telecommunications facilities for the exchange of 

Interconnection and operating information. COM—002 requires each Transmission 

Operator, Balancing Authority, and Generator Operator to have communications 

(voice and data links) with appropriate Reliability Coordinators, Balancing Authorities, and Transmission Operators. Such communications shall be staffed and available for addressing a real-time emergency condition. 

Pursuant to section 1839 of the Energy Policy Act of 2005 (EPAct 2005), the Secretary of Energy and the Commission studied and presented a report to Congress 
102

48The $2.5 million Duke and $50 million Reliant settlements were distributed to parties that 

opted into the global settlements based on the pre-October 2000 period percentages based on 

the allocation matrix of the global settlements. For parties that did not opt into the global settlements, the amounts are to be distributed based on a further Commission order in the Partnership/Gaming proceeding (generally Docket No. EL03-180). 49Order of Chief Judge Granting Minor Modification of Procedural Dates (March 12, 2007).

on the steps that must be taken to establish a system to make available to all transmission owners and RTOs within the Eastern and Western Interconnections realtime information on the functional status of all transmission lines within such Interconnections. The study assessed technical means for implementing a transmission 

information system and identified the steps the Commission or Congress would need 

to take to require implementation of such system. This joint report responded to 

Congress’ directive and addressed whether technology provides a means to address 

deficiencies in the transmission monitoring system and to provide better information 

to all system operators. Out of the nine steps identified in the report three steps 

deal with communication infrastructure and data sharing issues as follows:

Step 3. Identify the communications infrastructure required and related security and operating issues. 

Step 4. Define data requirements. 

Step 6. Decide what data should be shared, with whom, and when.

The report concluded, among other things, that a real-time transmission monitoring system requires that uniform data and common data storage be used across 

the system so that all system operators can share and use each other’s data with 

ease. 

Question 11. As I understand it, the Commission has been accumulating funds obtained from settlements with entities involved in the Western power crisis in a dedicated fund that will be distributed among the victims of the Western power crisis 

in ‘‘Phase II’’ of the ‘‘Gaming/Partnership’’ proceedings, Phase I of which is now ongoing before the Commission. In connection with this fund, please: (1) identify by 

name, FERC docket number, and settlement amount the settlements that the Commission intended to go into this dedicated fund; (2) quantify the amount of money 

currently in the fund; and, (3) explain any discrepancy between the amount of settlements, disgorgements and refunds recovered by the Commission and the amount 

currently in the dedicated fund. 

Answer. Provided below is a table showing the breakdown of settlement amounts 

by name and FERC docket number. Settlement amounts totaled in excess of $95 

million, $63 million of which has been received by the Commission. Of the $63 million, nearly three-quarters ($46 million) was associated with two cases and has been 

disbursed, consistent with the terms of the global settlements in those cases.48 The 

roughly $32.5 million not yet in receipt of the Commission concerns two cases that 

are pending rehearing before the Commission; thus the decisions and amounts in 

those cases are not final. 

The Administrative Law Judge is scheduled to issue her Initial Decision in Phase 

I on June 8, 2007.49 After the issuance of this Initial Decision, Phase II addressing 

the distribution of funds is planned to commence. 
103

Company Docket Nos. Settlement Amounts Amount Paid Amount Dis- bursed Remaining Es- crow Balance Receivable Due Status 

American Electric 

Power Service Corporation.

EL03-137-000 ....... 45,240.00 45,240.00 ........................ 45,240.00 ........................ Paid in Full 

City of Redding, 

California.

EL03-149-000, 

EL03-182-000.

6,300.00 6,300.00 ........................ 6,300.00 ........................ Paid in Full 

Colorado River 

Commission of Nevada.

EL03-184-000 ....... 996,145.00 996,145.00 ........................ 996,145.00 ........................ Paid in Full 

Duke Energy 

North America, LLC.

INO3-10-000, 

PA02-2-000.

2,500,000.00 2,500,000.00 2,450,713.58 49,286.42 ........................ Paid in Full 

Duke Energy 

North America, LLC.

PA02-2-000 ........... 57,441.84 57,441.84 ........................ 57,441.84 ........................ Paid in Full 

Duke Energy 

Trading and Marketing, LLC.

EL03-152-000 ....... 549,973.00 549,973.00 ........................ 549,973.00 ........................ Paid in Full 

Dynegy Power 

Marketing, Inc..

EL03-153-000 ....... 3,014,942.00 3,014,942.00 ........................ 3,014,942.00 ........................ Paid in Full 

Dynegy, Inc./NRG 

Enrgy, Inc./West Cost Power, Inc./Segundo Power LLC/Long Beach Generation, LLC/ Cabrillo Power, LLC.

EL00-95-000, 

EL00-98-000, EL01-10-000, INO3-10-000, PA02-2-000.

1,329,332.11 1,329,332.11 ........................ 1,329,332.11 ........................ Paid in Full 

El Paso Electric/

Enron Power Marketing.

EL02-113-000, 

EL03-180-000, EL03-154-000.

32,528,766.00 ........................ ........................ ........................ 32,528,766.00 Rehearing Pending 

Enron Power Marketing. EL00-95-000 ......... 537,814.01 537,814.01 ........................ 537,814.01 ........................ Paid in Full Enron Power Marketing. EL03-137-000 ....... 15,000.00 15,000.00 ........................ 15,000.00 ........................ Paid in Full Hanover Ventures, 

L.P. (ETHAN).

EL05-111-003 ....... 16,600.00 16,600.00 ........................ 16,600.00 ........................ Paid in Full 
104

Company Docket Nos. Settlement Amounts Amount Paid Amount Dis- bursed Remaining Es- crow Balance Receivable Due Status 

Hinson Power 

Company, LLC.

EL05-111-004 ....... 5,000.00 5,000.00 ........................ 5,000.00 ........................ Paid in Full 

IPP Energy, LLC EL05-111-006 ....... 30,000.00 30,000.00 ........................ 30,000.00 ........................ Paid in Full IDACORP Energy 

L.P..

EL00-95-183 ......... 83,373.00 83,373.00 ........................ 83,373.00 ........................ Paid in Full 

Mirant Corporation. EL00-98-000 ......... 2,204,208.83 2,204,208.83 ........................ 2,204,208.83 ........................ Paid in Full Modesto Irrigation 

District.

EL03-193-000 ....... 60,000.00 60,000.00 ........................ 60,000.00 ........................ Paid in Full 

Modesto Irrigation 

District.

EL03-159-000 ....... 14,304.00 14,304.00 ........................ 14,304.00 ........................ Paid in Full 

Puget Sound Energy, Inc.. EL03-169-000 ....... 17,092.00 ........................ ........................ ........................ 17,092.00 Rehearing Pend- ing Reliant Energy 

Services, Inc..

EL03-59-000, 

INO3-10-000, PA02-2-000.

50,000,000.00 50,000,000.00 44,183,754.64 5,816,245.36 ........................ Paid in Full 

Reliant Resources, 

Inc..

EL00-170-000 ....... 836,000.16 836,000.16 ........................ 836,000.16 ........................ Paid in Full 

San Diego Gas & 

Electric Company.

EL03-172-000 ....... 27,972.00 27,972.00 ........................ 27,972.00 ........................ Paid in Full 

Williams Energy 

Services Corporation.

EL00-95-000, 

EL00-98-000.

760,333.00 760,333.00 ........................ 760,333.00 ........................ Paid in Full 

TOTAL .................. 95,635,836.95 ....... 63,089,978.95 46,634,468.22 16,455,510.73 32,545,858.00
105

50See California Parties Settle Energy Crisis Refund Claims with Portland General, Southern 

California Edison press release (March 12, 2007). Note that it is unclear from this press release 

whether the recovery rate applies only to Enron’s unsecured claim or whether the rate is an 

average that applies to both of Enron’s claims. 51See, for example, Form 8-K, Mirant Corp., December 15, 2005. 

Question 12. The Commission has regularly touted the billions of dollars in refunds it has obtained from entities involved in the meltdown of the Western power 

markets in 2000-01. In the Commission’s 2005 Report to Congress (‘‘The Commission’s Response to the California Energy Crisis and Timeline for Distribution of Refunds’’), for example, the Commission claimed that, it has accepted 24 settlements 

in various dockets, with over $6.3 billion in refunds or other compensation to market participants. In connection with this claim, I note that substantial portions of 

the settlement amounts are in the form of bankruptcy claims that may be worth 

little or nothing after the claims are settled in the bankruptcy process. The EnronTrial Staff settlement, for example, contains a $400 million ‘‘penalty’’ claim against 

Enron that will never be collected because ‘‘penalty’’ claims are subordinated and 

worth nothing in the Enron bankruptcy. Of the $6.3 billion the Commission has 

claimed, please identify: (1) how much of that total is comprised of claims in bankruptcy whose value will be reduced or eliminated by operation of the bankruptcy 

laws (please identify these totals in nominal dollars included as part of the $6.3 billion figure and in actual dollars likely to be recovered through bankruptcy); (2) how 

much of that total has been returned to electric ratepayers in California, the Pacific 

Northwest, and the Southwest. 

Answer. With regard to your question concerning how much of the $6.3 billion is 

comprised of claims in bankruptcy, of the settlements reported in the Commission’s 

2005 Report to Congress, those of Enron and Mirant included claims in bankruptcy. 

These settlements, like all creditors’ claims, were subject to the laws of bankruptcy 

and the plans that were ultimately confirmed by the bankruptcy courts. These settlements comprise $1.653 billion out of the $6.3 billion figure referred to in your 

question. The table below indicates the nominal value of the claim, estimated recovery percentage and estimated value, in millions of dollars. Please note that we do 

not have record evidence on the estimated recovery percentage, and are estimating 

the percentages from generally available public information.

Nominal 

Value 

Recovery 

(Percent) 

Estimated 

Recovery 

Enron Unsecured Claim ................................. 875 50 35 306

Enron Subordinated Claim ............................ 600 0 0

Enron Unsecured Claim to Salt River 

Project .......................................................... 2.7 35 0.9

Mirant Unsecured Claim ................................ 175 51 100 175

Total ...................................................... 1,653 ................ 482

With regard to your question of how much of the $6.3 billion has been returned 

to electric ratepayers in California, the Pacific Northwest and the Southwest, while 

the Commission has approved or facilitated settlements resulting in over $6.3 billion 

of refunds or other benefits to California and others, the Commission does not direct 

how these funds are ultimately distributed to retail or end use ratepayers. Moreover, there was no single approach to the form of refunds or benefits as these were 

separate settlements which adopted various mechanisms for returning dollars to 

ratepayers. 

In the case of certain global settlements approved by the Commission, they have 

provided a matrix detailing the allocation of funds that provides for the net wholesale buyers in the market to receive refunds that they would be due pursuant to 

the various orders the Commission has entered in the Refund Proceedings. The largest recipients of these settlements have been the three California investor owned 

utilities, Pacific Gas and Electric, Southern California Gas, and San Diego Gas and 

Electric. It will be the responsibility of the California Public Utilities Commission, 

which is also a party to most of these global settlements, to ensure the monies are 

appropriately passed through to affected California retail ratepayers. In addition to 

the three California investor-owned utilities, entities outside of California were also 

listed. For example, in the case of Dynegy’s settlement, the settlement agreement 

matrix included entities from the Northwest such as Idaho Power and the City of 

Seattle. Similarly, in the case of Reliant’s global settlement, entities from the Southwest such as Salt River Project and Arizona Public Service Company were listed. 
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Again, the decision of how to ultimately pass on these amounts to any affected retail 

ratepayers is appropriately within the province of the state regulator or municipal 

entity. 

For other (non-global) types of settlements, such as Reliant’s settlement concerning withholding, the agreement was that Reliant would make payment directly 

to customers of the California Power Exchange (PX) that purchased energy in the 

PX’s day-ahead market on the days in question in which Reliant withheld energy 

from the market. 

In addition to these types of settlements or settlement provisions that identify 

parties to whom refunds should flow, others involved future rate reductions, payments to low income home energy programs, and other considerations such as contract renegotiations which will provide real benefits to various segments of the public. 

Question 13. In the Enron bankruptcy, the bankruptcy judge repeatedly barred 

utilities from proceeding against Enron before FERC if their claims involved what 

the bankruptcy judge deemed to be state law claims. As you know, the bipartisan 

Energy Policy Act of 2005 (Public Law 109-58) included a provision (Section 1290) 

granting FERC ‘‘exclusive jurisdiction’’ under the Federal Power Act to determine 

whether a requirement to make termination payments for power not delivered by 

the seller is unlawful due to a contract that is unjust or unreasonable or contrary 

to the public interest. In the case of Public Utility District No. 1 of Snohomish Co., 

Washington, 115 FERC Paragraph 61,375 (June 28, 2006), can you explain why the 

Commission read this provision to set aside the termination payments in question 

under ‘‘New York law’’ rather than under the ‘‘Federal Power Act’’? 

Answer. Under the Federal Power Act (FPA), the Commission traditionally has 

had concurrent jurisdiction with the courts over state-law issues involving FERCjurisdictional contracts, and exclusive jurisdiction over federal issues arising under 

the FPA. With respect to state-law issues related to FERC-jurisdictional contracts, 

the courts and the Commission have applied the doctrine of primary jurisdiction to 

allocate initial decision-making responsibility between them. The factors considered 

by the Commission in determining whether to exercise primary jurisdiction are 

whether the Commission possesses some special expertise which makes the case peculiarly appropriate for Commission decision, whether there is a need for uniformity 

of interpretation of the type of question raised by the dispute, and whether the case 

is important in relation to the regulatory responsibilities of the Commission. Thus, 

pursuant to traditional FPA authority, the Commission has at times exercised its 

concurrent jurisdiction to decide state-law contract issues (such as those related to 

the Snohomish termination payment case) under the doctrine of primary jurisdiction. In these cases, it has been the Commission’s traditional practice to apply the 

rules of contract interpretation prevailing in the state whose laws govern the contract. 

Prior to the enactment of section 1290, the bankruptcy court had determined that 

the issue of whether the seller was entitled to the termination payment under the 

Commission-filed contract was to be decided by the bankruptcy court, not the Commission. The Commission interpreted section 1290 to overturn the bankruptcy 

court’s decision and to give the Commission exclusive jurisdiction over all issues related to the Enron termination payment dispute, whether acting under concurrent 

jurisdiction to decide issues that are necessary to the exercise of its FPA regulatory 

authority or under exclusive jurisdiction under the FPA. Pursuant to this interpretation of section 1290, the Commission on June 8, 2006, issued an order granting 

Snohomish’s request that the Commission deny Enron’s claim for a contract termination payment of $116.8 million, plus interest. The Commission’s decision was 

based on an interpretation of New York contract law. The United States District 

Court for the Southern District of New York subsequently found that the Commission does not have exclusive jurisdiction under section 1290 to determine the disputed termination payment issue. This issue of interpretation of section 1290 and 

the Commission’s assertion of primary jurisdiction is currently before the United 

States Court of Appeals for the Second Circuit, in which the United States of America is appealing a lower court decision that section 1290 did not afford the Commission any additional authority. The Commission encouraged the Justice Department 

to appeal the lower court’s decision to the Second Circuit. 

Question 14. FERC, on a 3-2 vote, recently announced a policy that if a power 

contract is silent, as to the appropriate standard of review, the Commission will review challenges to rates charged pursuant to that contract pursuant to the MobileSierra public interest standard as opposed to the statutorily required just and reasonable standard contained in the Federal Power Act. How can you reconcile this 

policy pronouncement with two recent decisions issued by the U.S. Court of Appeals 
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52Public Utility Dist. No. 1 of Snohomish County, Wash., et al. v. FERC, No. 03-74208 (9th 

Cir. December 19, 2006), and California Public Utils. Comm’n v. FERC, No. 0374207 (9th Cir. 

December 19, 2006). 53Pub. Util. Dist. No. 1 v. FERC, 471 F.3d 1053, 1061 (9th Cir. 2006), 471 F.3d at 1061. 54 Californians for Renewable Energy, Inc. v. California Public Utilities Commission,—119 

FERC 61,058 (April 10, 2007).

for the Ninth Circuit that held that the public interest standard is inappropriate 

for certain market-based rate arrangements? 

Answer. The Commission issued its proposed rule on Mobile-Sierra by a vote of 

2-1. As I indicated in the answer to your question 4, the proposed rule is consistent 

with the 9th Circuit decisions.52 In those decisions, the court held that, where the 

parties did ‘‘not preclude the limited Mobile-Sierra review’’ in the terms of their contract, there is a ‘‘presumption that parties have negotiated a contract that is just 

and reasonable between them and therefore triggers the Mobile-Sierra public interest mode of review.’’53 I recognize, however, that the U.S. Court of Appeals for the 

Ninth Circuit disagreed with the Commission on several other issues. Because the 

case is now pending both on remand and in the U.S. Supreme Court, however, I 

cannot comment further on how those issues may be addressed in any remand. 

I wish to emphasize that the U.S. Court of Appeals for the Ninth Circuit was reviewing the Commission’s market-based rate program as it existed in 2000-2001. 

Since that time, however, the Commission has strengthened the program considerably. As we held last month in a California order ‘‘[s]ince 2001... the Commission has undertaken numerous measures to address market structure flaws and potential market manipulation in California markets and markets nationwide to ensure there are appropriate market safeguards in place to prevent a repeat of the 

California 2000-2001 energy crisis.’’54 We summarized several of those measures as 

follows: 

The Commission’s ability to respond to the instances of market manipulation during the 2000-2001 energy crisis was also limited by the minimal enforcement authority it possessed at the time. Following the crisis, the Commission initiated several investigations into potential market manipulation 

incidents. To deter the recurrence of market manipulation in the future, the 

Commission adopted the Market Behavior Rules in November 2003. These 

rules set guidelines for the conduct of sellers with market-based rate authority, and provided remedies for manipulative behavior and other market 

abuses by such sellers. 

Further, the Commission sought from Congress additional regulatory 

tools to deter market power abuse, comparable to those possessed by other 

economic regulatory bodies, such as the Securities and Exchange Commission. As a result, in the Energy Policy Act of 2005 (EPAct 2005), Congress 

provided enhanced authority over market manipulation and market transparency, and also gave the Commission civil penalty authority to deter market manipulation and other violations of law. 

Specifically, EPAct 2005 added to the FPA an explicit prohibition on the 

use of manipulative or deceptive devices in connection with the purchase 

or sale of electric energy or transmission service subject to the jurisdiction 

of the Commission, in contravention of the Commission’s rules and regulations, expanded the Commission’s ability to impose civil penalties, and increased criminal penalties for violations of Part II of the FPA or any rules 

or orders thereunder, and expanded the Commission’s authority to order refunds. 

To implement the newly granted anti-manipulation authority, the Commission promptly issued Order No. 670, which adopted a new rule prohibiting the employment of manipulative or deceptive devices or contrivances 

in wholesale electricity and natural gas markets. In addition, the Commission issued an Enforcement Policy Statement to provide guidance to the industry on how the Commission intends to determine remedies for violations, including applying its new and expanded civil penalty authority. 

In addition, in 2003, the Commission issued its Policy Statement on Electric and Natural Gas Price Indices that explained its expectations of natural gas and electricity price index developers and the companies that report transactions data to them. This effort has resulted in significant improvements in the amount and quality of both price reporting and the information available to market participants. 

The Commission has also strengthened its oversight of markets through 

the creation in 2001 of a separate Office of Enforcement (OE), which protects customers by timely identifying market problems and recommending 
108

appropriate remedies to address market problems, assuring compliance 

with rules and regulations, and detecting and crafting penalties to address 

market manipulation. Among other duties, the OE ensures the timely and 

accurate filing of Electric Quarterly Reports (EQR) required to be filed by 

all public utilities and coordinates the work of the Market Monitoring Units 

(MMUs) associated with Independent System Operators and Regional 

Transmission Organizations. The Commission’s use of filed EQR data and 

the increased role of the MMUs in monitoring and reporting market performance are important tools the Commission uses to determine if there are 

indicia of the exercise of market power. 

Further, the Commission has a program for authorizing and overseeing 

market-based rates that has been strengthened since 2001. This program 

first requires a seller seeking a market-based rate authorization to demonstrate that neither it nor its affiliates have market power in generation 

or transmission (or that any such market power is sufficiently mitigated). 

If such demonstration is made, the grant of the market-based rate authorization is conditional on adherence to a code of conduct, the quarterly filing 

of transaction information through the EQRs, and the filing of any change 

in status. 

To clarify and improve further this program, in May 2006, the Commission issued a Notice of Proposed Rulemaking (MBR NOPR), in which the 

Commission proposed to amend its regulations governing market-based rate 

authorizations for wholesale sales of electric energy, capacity and ancillary 

services by public utilities. The MBR NOPR represents a significant step 

in the Commission’s efforts to clarify and codify its market-based rate policy 

by providing a stringent up-front analysis of whether market-based rates 

should be granted, by including prophylactic conditions and ongoing filing 

requirements in all market-based rate authorizations, and by reinforcing its 

ongoing oversight of market-based rates. 

All these measures taken by the Commission have strengthened the Commission’s market-based rate program, its market oversight and enforcement 

capabilities, and its ability to impose meaningful remedies, as compared to 

the 2000-2001 energy crisis time period. The Commission’s duty is to ensure that consumers pay just and reasonable rates, and these mechanisms 

achieve those goals. One way the Commission protects customers is by providing rate stability through the protection of sales contracts. The failure 

to protect parties’ contractual expectations can harm customers by reducing 

the willingness of sellers and buyers to contract for rate certainty through 

fixed-rate contracts or by deterring sellers and buyers from making the investment needed to support the long-term contracts. The Commission’s improved market-based rate program provides the foundation to ensure that 

sellers and buyers can continue to rely on market-based rate contracts to 

provide price certainty, flexibility in contract terms, and the contract stability necessary to support new investment.

Question 15. Given the recent Ninth Circuit decisions involving the Commission’s 

use of the Mobile-Sierra public interest standard for market-based rate contracts 

signed during the dysfunctional western market, would you agree that the Commission must first find a contract is just and reasonable before employing another 

standard of review? 

Answer. Please see my answers to Questions 4 and 14. 

Question 16. On April 11, 2007, the Commission issued an Order initiating proceedings into potential improprieties by certain Enron expert witnesses and attorneys relating to data that the Commission ordered to be disclosed in its investigation of the Western power market crisis (FERC Docket No. PA02-2). I applaud the 

Commission for taking seriously these allegations as they go to the heart of the 

Commission’s regulatory mission—without full, frank and complete disclosure from 

regulated entities, the Commission simply will not have the information it needs to 

succeed. I appreciate that you cannot comment on the matters at issue in the April 

11 order and the hearing now underway. However, in light of the larger issues 

raised by the order, what measures has the Commission taken to review the apparently inadequate and less-than-frank submissions made by various entities in response to the Commission’s investigatory orders in PA02-2 and in other cases arising out of the Western power crisis, and to further investigate and prosecute possible misconduct in relation to those submissions? 

Answer. As you note, the Commission’s regulatory efforts depend on full and honest submissions by parties and their representatives. Improper withholding of requested information will not be tolerated. Any indications of misconduct by parties 
109

or their representatives will be pursued thoroughly. However, I cannot disclose at 

this time the scope or nature of any non-public investigations by the Commission 

or its staff. 

Question 17. Chairman Kelliher, what do you see as FERC’s ongoing role with regard to the implementation of NERC’s reliability standards? What is FERC’s plans 

for oversight and consistency of implementation in each region across the country? 

Answer. The Commission’s continued presence is required in all areas of reliability, including: standards development, compliance and enforcement, investigation and analysis, physical and cybersecurity, and reports and assessments. New 

FPA section 215 gave the Commission the authority, for the first time, to approve 

mandatory reliability standards proposed by the ERO. The Commission has already 

approved 83 standards as mandatory and enforceable. We also directed that 56 of 

these standards be modified to better protect reliability. The Commission also has 

pending before it many other standards, including cybersecurity standards, and is 

carefully reviewing these standards. Prospectively, the Commission intends to continue working with the ERO, the regional entities and the industry to strengthen 

reliability standards. Commission staff actively monitors the standards development 

process to provide timely information and feedback to stakeholders. In addition to 

our involvement with standards development, Commission staff will participate in 

the regional planning processes which are intended to identify reliability problems 

and set mitigation plans in place to address them before they even materialize. In 

order to assist the regions with enforcement matters, I have authorized Commission 

staff to join with the regional entities in a representative sampling of regular compliance audits in each of the regions shortly after they begin. Commission staff will 

also work with the regional entities and ERO to investigate selected incidents on 

the bulk bower system. Commission staff will also prepare and/or manage on-going 

reports and assessments on various issues concerning the reliability and security of 

the nation’s bulk power system. 

As I detailed above, to exercise our oversight responsibility and to ensure consistent implementation of the standards across all regions of the country, Commission staff will participate with the regional entities in a representative sampling of 

regular compliance audits in each of the regions. Commission staff will also investigate selected incidents on the bulk power system, working with the regional entities and ERO or even independently, as events warrant. Further, although the ERO 

and the Regional Entities have first-line responsibility to ensure consistent enforcement of the standards, the Commission will annually review the performance of the 

ERO and the Regional Entities to ensure that they are carrying out their responsibilities appropriately. In addition, as part of its regulatory role, the Commission 

requires the ERO to file any remedial directive, approved mitigation plans, settlements or penalties it or a Regional Entity issues to any User, Owner or Operator 

of the bulk power system. The Commission has the oversight authority, and will review each of these submissions to ensure that they are consistent across regions and 

commensurate with the severity of the violation and with the risk that they pose 

to the reliability of the bulk power system. Any affected entities may appeal the decisions of the ERO and Regional Entities. 

Commission staff has recognized more resources are necessary for reliability and 

reliability-related enforcement. As a result, I will soon request to the relevant appropriations committees that FERC’s FY08 appropriations be funded at $9 million 

above the President’s FY08 budget request. Based on our experience in implementing our authority under new FPA section 215, we have determined that the 

resource requirements for implementing the reliability program were underestimated. Increased Commission staff presence is required in standards setting, cyber 

security, and oversight and investigation. The Commission is a self-supporting agency and would recover the additional appropriations through fees, as it does all of 

its costs, and will continue to operate at no net cost to the taxpayer. 

Question 18. In regulated parts of the U.S. where states set rates, consumers are 

served by cost-of-service rates. In ‘‘deregulated’’ states where rates are regulated by 

FERC, consumers only have access to market-based rates. In the 12 states that do 

not have rate caps as of December 2006, and are therefore fully deregulated, the 

average rate charged to households is 13.4 cents per kilowatt hour-48 percent higher 

than the average rate of 9.1 cents per kilowatt hour in the 38 regulated states. Can 

you explain how rates in cost-of-service states are lower than rates in FERC-regulated states? In light of this, can you explain that market-based rates are ‘‘just and 

reasonable’’ if they are higher than cost-of-service rates? 

Answer. Differences in retail rates charged in various states depend on many factors. For example, a region relying extensively on hydropower will have different 

costs than a region largely dependent on fossil fuels, particularly natural gas. Deferrals of cost recovery adopted by state law or regulation also may cause differences. 
110

Transmission congestion also can affect access to low-price generators. These differences existed even before retail competition was initiated, and states that adopted retail competition generally did so in reaction to high prices produced by traditional cost-of-service regulation. As a recent report noted, ‘‘in 1998, customers in 

New York paid more than two and one-half times the rates paid by customers in 

Kentucky. Rates in California were well over twice the rates in Washington.’’ Report 

to Congress on Competition in Wholesale and Retail Markets for Electric Energy at 

25 and 87, Electric Energy Market Competition Task Force. Untangling the factors 

for differences in retail rates is difficult, and studies seeking to identify the effects 

of competition have reached conflicting results. Market prices vary based on a range 

of conditions, and at different times may be below or above cost-based rates. Market 

prices may be below cost-based prices when electricity supply significantly exceeds 

local needs, but above cost-based prices when additional supplies are needed. 

Competition is national policy in wholesale power markets, but the Commission 

does not rely solely on competition to assure just and reasonable prices. We rely on 

a combination of competition and regulation. In some cases, wholesale competition 

has not worked as envisioned. For example, in some areas, such as California, 

wholesale markets have not been well designed and those flaws have harmed consumers. The proper response is to change the mixture between our reliance on competition and regulation to assure more competitive markets and more effective regulation. We believe the new regulatory tools Congress gave us in EPAct 2005 can 

help improve competition in wholesale power markets. In this regard, the Commission has taken a number of steps over the years to strengthen markets and EPAct 

2005 gave the Commission important new authority to police market manipulation 

and assess civil penalties for misconduct. 

It is important to remember that national policy has evolved over the last 30 

years to support competition for very important reasons. Traditional regulation that 

relies solely on the monopoly provision of electric service can discourage innovation, 

impede entry by more efficient competitors, and increase risks for consumers. The 

three major pieces of energy legislation enacted over the past thirty years (Public 

Utility Regulatory Policies Act of 1978, Energy Policy Act of 1992 and Energy Policy 

Act of 2005) were all designed to counteract these flaws. 

Although competition is national policy, I respect the decisions of states that have 

retained the regulated model for serving retail customers and believe that national 

efforts to increase wholesale competition are fully compatible with varying state 

choices regarding competition or regulation. Whatever the state choice, greater 

wholesale competition can provide better opportunities for load serving entities to 

provide reliable and economic service to their retail customers. 

One of competition’s clear benefits to customers is the shift of risk away from consumers. As an example, many generating units were built in recent years outside 

of cost-based rates and, particularly in the case of natural gas fired generation, the 

investors in those units have suffered the risks of poor investments. In some instances, these risks have led to bankruptcies. In these instances, it is the investor 

who bore the losses, not the consumer. That stands in stark contrast with the nuclear cost overruns of the 1970s and 1980s, which were largely borne by consumers 

and recovered through regulated rates. Other benefits of competition include improvements in nuclear plant operation and construction of more efficient generating 

units. I expect that competition and innovation will only increase in the future, as 

the Nation demands greater reliance on demand side resources and renewable resources. Vigorous wholesale competition is well suited to facilitate the development 

of these resources. 

Question 19. Right now, a coal fired power plant is far, far cheaper to run than 

a natural gas power plant. Currently FERC allows all sellers in a market to charge 

the same market-based rates, which gives a huge economic advantage to low-cost 

coal-fired power plants. Do you believe that, under the current market-based rate 

system, FERC is sending a market-signal to build new coal fired power plants? 

Answer. During most of the period where the Commission has authorized market 

based rates, most generation additions were gas-fired. Current interest in building 

coal generation is largely a reaction to high natural gas prices and reflects a desire 

for more fuel diversity in electricity supply additions, wholly unrelated to Commission rules. I do not believe the Commission, through its current market-based rate 

program, is sending a signal to build new coal-fired power plants to the exclusion 

of other fuel types. Under the Commission’s market-based rate program, a seller 

must demonstrate that it lacks or has mitigated market power in generation and 

transmission, that it cannot erect other barriers to market entry, and that there is 

no affiliate abuse or reciprocal dealing. A seller’s ability to sell at market-based 

rates has nothing to do with the fuel types of the generating plants from which it 

sells power. In addition, with respect to organized energy markets (i.e., real-time 
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55See California Independent System Operator Corp., 119 FERC Paragraph 61,061 (2007). 

and day-ahead markets) administered by RTOs and ISOs, in which energy is priced 

based on a single price auction, incentives are for low cost generation to come on 

line and enter the market, irrespective of fuel type. Any generator that has low fuel 

costs, including wind, hydro and nuclear, will receive benefits when power is needed 

and prices rise. 

Question 20. In Order No. 661, FERC issued standards for wind power generators 

to interconnect to the grid. I understand that, based on regional recommendations, 

it is possible that the Commission may consider revising these standards. However, 

every time wind interconnection standards are revised, wind turbine manufacturers 

need to change the design of their machines to ensure compatibility with the new 

standards. What does FERC plan to do to ensure that, if the interconnection standards are revised, the new standards will be prospective in nature and will ensure 

that there will be a sufficient transition period to permit turbine manufacturers 

enough time to change their designs? 

Answer. I agree this is an important issue. Whenever the Commission proposes 

a rule that would require the industry to implement new policies or technical standards, the Commission places a high priority on maintaining a stable and predictable 

regulatory environment for the industry. Indeed, Order No. 661 provides a clear example of this philosophy. In response to the Commission’s proposal to implement 

new interconnection standards for wind generators, several commenters argued that 

a transition period was needed to prevent added costs and delays and to protect previously executed wind equipment purchase agreements and power purchase arrangements. They noted that, without a transition period, wind turbines that were 

in the process of being manufactured would require substantial changes to meet the 

new requirements. I and Commission staff have established an ongoing dialogue 

with stakeholders on these issues. Accordingly, the Commission adopted the commenters’ proposal to allow a 6-month transition period before the new interconnection standards would take effect. The Commission stated that it would be unfair and 

unreasonable to apply the new standards immediately or retroactively, and noted 

that the transition period allows wind equipment currently in the process of being 

manufactured to be completed without delay or added expense. 

The Commission recognizes, however, that technical standards may need to be revised from time to time. For that reason, the Commission stated in Order No. 661 

that it would consider a future industry petition to revise the standards to conform 

to a NERC-developed standard. The Commission also stated that if another entity 

develops an alternate standard, a transmission provider may seek to justify adopting it as a variation from the standards required by Order No. 661. Again, if such 

revisions are needed, we would consider requiring a transition period if one is 

shown to be necessary to avoid added costs and the disruption of prior commercial 

arrangements. In addition, I would emphasize that the Commission rarely applies 

new rules retroactively. 

Question 21. FERC policy generally requires that the beneficiaries of a new transmission facility must pay for that facility. Assuming a transmission facility is primarily built to ensure that new renewable energy generation comes on line, does 

the Commission take into account the widespread benefits of the added renewable 

electric generation, including reduced greenhouse gas emissions, lower natural gas 

prices and the ability of utilities to meet state renewable portfolio standard requirements? 

Answer. The Commission recently approved a proposal by the California ISO to 

enhance development of renewable resources.55 The proposal approves a creative 

process to finance and build transmission interconnection facilities to connect new 

renewable resources to the transmission grid by allocating some of the costs of these 

facilities to the broader California market. In approving the proposal, the Commission relied on the regional transmission planning process to assess whether the system benefits from a transmission facility are greater than the costs of such a facility. System benefits may include reduced greenhouse gas emissions, fuel supply diversity, and meeting a state’s renewable portfolio standard. 

In voting for this Commission action, I stated that this was:

[A]n important order that should encourage greater fuel diversity in our 

electricity supply, by removing barriers to increased development of renewable energy... The California Independent System Operator’s (California 

ISO) proposal should make it easier for California and other states to meet 

their targets in various state renewable portfolio standards . . . In this 

order we recognize the unique characteristics of renewable energy 

projects... and our action recognizes that a large and growing number 
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56See Montana Alberta Tie, Ltd., 116 FERC 61,071 (2006). 57 In performing all screens, applicants are required to prepare them as designed, and must 

use the most recent 12 months’ historical data to provide a ‘‘snapshot in time’’ depiction of the 

of states have established renewable portfolio standards, and the Congress 

is considering adopting a federal standard. Our action recognizes and accommodates these state policy decisions.

In addition, in the past year the Commission granted preliminary approval to a 

proposal to operate a new merchant transmission line in Montana that would provide access to the transmission grid for a large amount of newly-developed wind 

generation and provide the first direct transmission connection between the U.S. 

and Alberta, Canada.56

Question 22. Is the Commission’s grant of market-based rate authority deemed 

sufficient to find that a seller’s market-based rate contract is just and reasonable? 

If a market deemed dysfunctional means that all sellers should lose their marketbased rate authority? If not, how can a customer obtain redress under the just and 

reasonable standard of the Federal Power Act? 

Answer. If a seller is found by the Commission to lack or have mitigated market 

power and is authorized to sell at market-based rates pursuant to its Commissionfiled market-based rate tariff, then its subsequent contracts at market-based rates 

are presumed to be just and reasonable. If a market becomes dysfunctional, however, and the Commission finds that sellers can manipulate the market or otherwise 

exercise market power, the Commission can revoke the market-based rate authority 

of any such seller. This would preclude the seller from making further sales into 

the market at market-based rates. In addition, the Commission may also adopt market rules that mitigate the exercise of any market power (e.g., bidding restrictions 

or caps). Furthermore, with respect to any contracts entered into during a period 

of severe market dysfunction, based on recent court decisions by the U.S. Court of 

Appeals for the 9th Circuit, such market dysfunction could affect the presumption 

of justness and reasonableness typically afforded to those market-based contracts. 

A customer may seek redress under the Federal Power Act by filing a complaint 

with the Commission. That can result in a section 206 proceeding and the establishment of a refund effective date. In addition, if a customer has evidence of market 

manipulation, it may also contact our enforcement staff through the Commission’s 

Enforcement Hotline. 

RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR TESTER

Question 1. The Federal Energy Regulatory Commission is one of the most important and least understood regulatory bodies in the United States. Its authority over 

wholesale energy markets affects each American consumer, often without their 

knowledge. In the last ten years the energy markets have changed dramatically 

from a system largely controlled by state regulated, vertically integrated power companies to deregulated competitive markets. Unfortunately, in many instances markets have not developed and this has resulted in dramatically higher rates, and a 

volatility that did not exist under the regulated systems. Under a market system 

FERC assumes the responsibility of determining that wholesale generators meet 

just and reasonable rates. FERC also must promote competition in the market 

place. On May 18, 2006, FERC issued a ruling against the Montana Public Service 

Commission and the Montana Consumer Council determining that the PPL Montana did not have market power (Docket No. ER99-3491 et. al., PPL Montana I, 

LLC). The Montana Public Service Commission believes that this ruling may cost 

Montana consumers millions of dollars and do little to promote competition. The 

Montana Consumer Council and the Montana Public Service Commission first requested a rehearing of that case on June 16, 2006 then again on October 30, 2006, 

but have failed to receive a rehearing from FERC. This leads me to my additional 

questions for the record for Chairman Kelliher. What criteria was used in this case 

to determine whether rates from the wholesale generator were just and reasonable? 

What criteria was used in this case to determine whether rates from the wholesale generator were just and reasonable? 

Answer. PPL Montana, as is the case with nearly all sellers with market-based 

rate authority, was required to submit for filing an updated market power analysis 

every three years. This filing included two required indicative generation market 

power screens as well as information on the other three parts of the Commission’s 

four-part market-based rate screening analysis (addressing transmission market 

power, other barriers to entry and affiliate abuse). 

The two ‘‘indicative’’ screens for assessing generation market power provide a rebuttable presumption of whether market power exists for the applicant.57 The first 
113

applicant’s market presence. The snapshot in time approach is used to prevent applicants from 

manipulating study results based on speculative potential future events. 58For purposes of the preliminary screen to determine which applicant’s need a closer examination, the Commission has established a preliminary rebuttable presumption of market power 

if the applicant has a market share of 20 percent or more in the relevant market for any season. 59These 10 seasons and load conditions include super-peak, peak, and off-peak times for each 

of the Winter, Shoulder and Summer periods, as well as an additional highest super-peak period 

for the highest load conditions in the Summer. 60PPL Montana, LLC, 115 FERC Paragraph 61,204 at 41 (2006). April 14 Order at 105. 61 Although PPL Montana claimed that it’s own study showed that its highest market share 

was only 13.8 percent, the Commission found PPL Montana’s analysis to be flawed and inconsistent with our requirements of how to conduct the studies, and that a properly conducted 

study showed market shares in excess of 20 percent during some seasons. PPL Montana, LLC, 112 FERC Paragraph 61,237 at 29 (2005) (September 2005 Order). 

screen involves an analysis of whether the applicant is considered a pivotal electricity supplier to the market at the time of the seller’s annual system peak demand, and the Commission has found that this analysis is helpful in evaluating the 

potential of the applicant (including its affiliates) to exercise market power at the 

time of the annual peak demand. The second screen involves an analysis of the market share of uncommitted capacity of the applicant and its affiliates during each of 

the four seasons of the year. 

The Commission uses both a pivotal supplier and market share analysis because, 

taken together, they give a reasonable indication of whether an applicant has market power. The uncommitted pivotal supplier analysis focuses on the ability to exercise market power unilaterally. It essentially asks whether the market demand can 

be met absent the applicant and its affiliates during peak times. Thus, the pivotal 

supplier screen measures market power at peak times, and particularly in spot markets. If peak demand cannot be met without some contribution of supply by the applicant or its affiliates, the applicant is deemed pivotal. In markets (such as electricity) where demand for the service is not very responsive to even significant price 

changes, a pivotal supplier could extract significant monopoly profits during peak 

periods because customers have few, if any, alternatives. 

The uncommitted market share analysis indicates whether a supplier has a dominant position in the market, which is another indication of whether the supplier has 

unilateral market power and may indicate the presence of the ability to facilitate 

coordinated interaction with other sellers.58 The market share screen is also useful 

in measuring for each of the four seasons whether an applicant has a dominant position in the market based on the number of megawatts of uncommitted capacity 

owned or controlled by the applicant and its affiliates as compared to the uncommitted capacity of the entire relevant market. Thus, by using the two screens together, 

the Commission is able to measure market power both at peak and off-peak times, 

and the seller’s ability to exercise market power both unilaterally and in coordinated 

interaction with other sellers. 

If a seller fails one or more of the initial screens, there is a rebuttable presumption that such seller possesses market power. In such an instance the seller has two 

options. First, the seller can decline to pursue its request for market-based rate authority and instead offer a cost-based default tariff. Second, if such an applicant 

chooses not to proceed directly to offering mitigation such as cost-based rates, it 

must present a more thorough analysis using the Commission’s more sophisticated 

stage 2 market power test, the Delivered Price Test. The Delivered Price Test defines the relevant market by identifying potential suppliers based on market prices, 

input costs, and transmission availability, and calculates each supplier’s economic 

capacity and available economic capacity for 10 different seasonal and load conditions.59 The results of the Delivered Price Test can be used for pivotal supplier, 

market share and market concentration analyses. A detailed description of the mechanics of the Delivered Price Test is provided in an appendix to the Commission’s 

April 14 Order.60 The Delivered Price Test is based on longstanding Commission 

policy and has been applied for more than a decade in considering whether utility 

mergers raise market power concerns. 

In the case of PPL Montana, the Commission’s analysis of PPL Montana’s two 

preliminary generation market power screens indicated that PPL Montana’s share 

of uncommitted capacity in the NorthWestern control area exceeded 20 percent in 

at least one of the four seasons during the relevant time period. Consequently, PPL 

Montana failed the wholesale market share screen in the NorthWestern control 

area.61 Thus, on November 14, 2005, PPL Montana submitted the stage 2 Delivered 
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62For purposes of the order, the Commission reviewed only PPL Montana’s 2004 Delivered 

Price Test study since it was the only one constructed consistent with the April 14 and July 

8 Orders which require use of historical data. 63 As discussed more fully in my answer to question number 6 below, simultaneous transmission import limits are used by the Commission to measure the amount of competing generation supplies from surrounding areas that can physically access the target relevant geographic 

market for purposes of the market power analysis. 64 NorthWestern Corporation, Market Power Analysis filed under Docket No. ER03-329-006, 

December 14, 2005, Simultaneous Import Limitation Study. 65PPL Montana, LLC, 115 FERC Paragraph 61,204 at 41 (2006). April 14 Order, 107 FERC 

Paragraph 61,018 at 111. 66 Under the available economic capacity measure during the winter off-peak, when PPL Montana had its largest market share of 25 percent, total available economic capacity to compete 

in the NorthWestern control area was 2,127 MW and PPL Montana’s share of that was 524 MW. 67 NorthWestern reports market concentration measures below the critical threshold in all periods under the economic capacity measure when the only adjustment is for the expiring contracts. NorthWestern January 17, 2006 filing Exhibit WHH-3. 

Price Test analyses for 2004 and 2006.62 PPL Montana’s 2004 analysis used the 

transmission import capability 63 values for the NorthWestern control area that had 

been previously reported by NorthWestern, as adjusted by PPL Montana.64

After weighing all of the relevant evidence from the stage 2 Delivered Price Test 

study, the Commission concluded that PPL Montana had effectively rebutted the 

presumption of generation market power that had been previously indicated by the 

stage 1 preliminary screen failure, and satisfied the Commission’s generation market power standard for the grant of market-based rate authority.65 Specifically, the 

Commission found that PPL Montana’s 2004 Delivered Price Test results indicated 

that the market shares using the available economic capacity measure (which takes 

into account the applicant’s native load commitments) were below 20 percent in 7 

out of 10 season/load periods and were only slightly above 20 percent during three 

off-peak periods, with the highest market share at 25 percent.66 Moreover, the study 

showed that the market concentration test results were all well below the Commission’s threshold, even during peak periods. Further, the stage 2 test results also 

showed that PPL Montana was not a pivotal supplier in any season/load period. And 

although the stage 2 test results for economic capacity (which does not take into 

account native load commitments) showed that PPL Montana’s market shares were 

above 20 percent in five periods, the market concentration test results were below 

the Commission’s thresholds in all periods and the company was also not a pivotal 

supplier in any period. On balance, and after considering all of the relevant evidence 

the Commission concluded that there was not sufficient evidence to conclude that 

PPL Montana had market power in Northwestern’s market. 

Some of the more contentious factual issues arising in the PPL Montana case involved competing studies presented by other parties. For example, NorthWestern 

submitted it’s own Delivered Price Test study that included adjustments to account 

for 450 MW from expiring contracts it had with PPL Montana, the associated removal of PPL Montana’s native load reduction for these expiring PPL EnergyPlus 

contracts, and the further exclusion of wholesale sales to investor-owned utilities, 

and the exclusion of PacifiCorp’s and Puget’s capacity. The Commission considered 

these arguments and found that, even if we were to accept them, NorthWestern’s 

own study results did not necessarily support its contention that PPL Companies 

have market power. For example, NorthWestern’s study, with proposed adjustments, shows that the market concentrations for all periods under the available economic capacity measure would still be below the Commission’s threshold, except for 

one off-peak period where the market concentration failure was not for a large 

amount.67 In past cases, the Commission has consistently found that market concentration figures of this magnitude do not permit the exercise of market power. In 

addition, the Commission considered, among other things, claims that the results 

of a recent request for proposal (RFP) indicates that PPL Montana has market 

power in generation. However, the Commission concluded that the results of the 

RFP were insufficient to determine that PPL Montana has market power because, 

among other things, the prices it bid in the RFP were generally within the range 

of other bidders and Northwestern appeared to have several other supply alternatives to PPL Montana. 

Given the results of the two indicative screens and the results of the stage 2 Delivered Price Test analysis, the Commission’s action in this case was consistent with 

its previous action in other cases. The Montana parties have raised significant objections on rehearing that are pending and I can assure you the Commission will give 

careful consideration to those arguments. 

Question 2. How does FERC determine market share of a wholesale generator? 
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68 April 14 Order at 110. 69 April 14 Order at 95. 70 18 C.F.R. § 33.3(c)(i)(A) (‘‘Prior to applying the delivered price test, the generating capacity 

meeting this definition must be adjusted by subtracting capacity committed under long-term 

firm sales contracts and adding capacity acquired under long-term firm purchase contracts.’’). 71 Applicants presenting evidence that the relevant market is larger or smaller than the default relevant market (i.e., control area) must first complete the screens based on the control 

area as discussed above. 

Answer. Under the Commission’s first phase test, the market share screen measures for each of the four seasons whether a seller has a dominant position in the 

market based on the number of megawatts of uncommitted capacity owned or controlled by the seller and its affiliates as compared to the uncommitted capacity of 

all sellers in the entire relevant market. Uncommitted capacity is determined by 

adding the total nameplate capacity of generation owned or controlled through contract and firm purchases, less the seller’s operating reserves, native load commitments (equal to the minimum peak load day for each season considered) and longterm firm non-requirement sales. Uncommitted capacity from an applicant’s remote 

generation (generation located in an adjoining control area) is included in the applicant’s total uncommitted capacity amounts. 

Under the Commission’s second phase test (the Delivered Price Test), each supplier’s market share is calculated based on proportion of it’s capacity that is economically able to compete in the relevant market (based on the delivered price of 

power from that capacity) relative to the total amount of such economic capacity 

that is in the relevant market. Under this second phase test the Commission typically examines market shares for 10 different season/load periods, and based on 

both economic capacity (the Delivered Price Test’s analog to installed capacity) as 

well as available economic capacity (the Delivered Price Test’s analog to uncommitted capacity). Because the market shares for each season/load condition reflect the 

costs of the applicant’s and competing suppliers’ generation, the Delivered Price 

Test provides a more complete picture of the applicant’s ability to exercise market 

power in a given market than do the preliminary first phase screens.68 All of the 

Commission’s market share measures take account of the physical limitations of the 

affected transmission systems to accommodate trades. 

Question 3. How was this determined in Montana? 

Answer. The market share of the PPL Companies in the NorthWestern control 

area was determined as described in my answer to your question 1 above. 

Question 4. Does FERC ever deduct the generation that is under contract when 

determining market share? 

Answer. Yes, the Commission’s indicative screens use uncommitted capacity 

which is determined by adding the total nameplate capacity of generation owned or 

controlled through contract and firm purchases, less operating reserves, native load 

commitments and long-term firm non-requirement sales.69 Further, for purposes of 

calculating the available economic capacity measure of the Delivered Price Test applicants are allowed deductions of capacity that are tied to any longterm firm commitments to third parties.70

In the April 14 Order, the Commission stated that in performing all screens, applicants are required to prepare them as designed,71 and must use the most recent 

unadjusted 12 months’ historical data as a snapshot in time. The Commission reasoned that historical data have been proven to be more objective, readily available, 

and less subject to manipulation than future projections. 

Question 5. The Montana Public Service Commission and the Montana Consumer 

Council have requested rehearing regarding the above mentioned case on October 

30, 2006. When do you expect the Commission to act on this request for rehearing? 

Answer. This proceeding is contested and our rules prohibit me from disclosing 

the timing of future Commission action. However, I expect the Commission will act 

in the near future. 

Question 6. How does FERC determine availability on electrical transmission 

lines? 

Answer. For the purpose of our generation market power analysis, the Commission uses simultaneous transmission import limit studies (SIL) to determine the 

amount of available supplies that can reach the relevant control area given the market. The SIL study is a conservative analysis of the amount of capacity that can 

be imported into a control area relevant geographic market. The Commission believes the SIL approach to be a commonly used methodology for measuring transmission import capability in the electric industry. 

The Commission specifies the techniques that must be adhered to in conducting 

an SIL study which are provided in Appendix E of the April 14 Order. In addition 
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72For purposes of the indicative screens the only markets first-tier to the study area are considered for potential supplies to be imported. 

to other criteria, the Commission requires that the SIL be conducted using the 

methodologies outlined in the transmission providers Commission-approved OATT 

tariff, thereby making a reasonable approximation of simultaneous import capability 

that would have been available to suppliers in surrounding first-tier markets during 

each seasonal peak.72 The transfer capability should also include any other limits 

(such as stability, voltage, CBM, TRM) as defined in the tariff and that existed during each seasonal peak. 

Question 7. How does FERC reconcile contrasting opinions of availability from the 

owner and operator of transmission lines? 

Answer. To date in the market-based rate context, the Commission has not encountered such a situation. However, the Commission relies on actual historical operating practices as reflected in the OASIS postings Accordingly, if a dispute were 

to arise with regard to opinions of availability of transmission lines the Commission 

would evaluate the historical operating practices in determining the amount of 

transmission capacity that was available during the study period. 

Question 8. The primary task of FERC should be to protect consumers. Yet Montana wholesale generation rates have nearly doubled in a few short years. How does 

FERC intend to protect the consumers of Montana? 

Answer. I agree the primary task of the Commission is to guard the consumer. 

The Commission has taken a number of steps in recent years to protect consumers 

against unjust and unreasonable wholesale power prices. 

First, the Commission has strengthened its ability to police market manipulation 

and market power. I have argued for many years that the Commission should have 

express statutory authority to police market manipulation and assess civil penalties 

for such manipulation or other violations of law. EPAct 2005 gave the Commission 

this authority for the very first time. We have already exercised that authority in 

several cases, and our Office of Enforcement is vigilant in monitoring markets to 

prevent the exercise of manipulation or market power. We are also actively investigating alleged market manipulation. 

We have also strengthened our program for considering market-based rate applications. We have steadily tightened our test for granting market-based rates over 

the past few years, and now there are several large sellers that no longer have authority to make market based sales. These sellers include Entergy, Duke Power and 

Xcel, some of the largest utilities nationally. 

In addition, we have proposed to strengthen our generic rules for considering market-based rate applications. On May 19, 2006, the Commission issued a proposed 

rule, in which the Commission proposed to amend its regulations governing marketbased rate authorizations for wholesale sales of electric energy, capacity and ancillary services by public utilities. In the proposed rule, the Commission proposed to 

modify all existing market-based authorizations and tariffs so they would reflect any 

new requirements ultimately adopted in the final rule. This initiative represents a 

major step in the Commission’s efforts to clarify and codify its market-based rate 

policy by providing a more rigorous up-front analysis of whether market-based rates 

should be granted, including protective conditions and ongoing filing requirements 

in all market-based rate authorizations, and reinforcing its ongoing oversight of 

market-based rates. The specific components of this rulemaking proceeding, in conjunction with other regulatory activities, are designed to ensure that market-based 

rates charged by public utilities are just and reasonable. 

Second, the Commission has worked hard to support the construction of new infrastructure that is necessary to provide consumers with reliable and reasonably 

priced electricity. The Commission has certificated over 9,400 miles of new natural 

gas pipeline capacity since 2000. This action is critically important because natural 

gas is a primary heating fuel in many areas of the country and, in addition, is a 

primary driver of electricity prices in many regions. 

The Commission has also worked hard to stimulate new electric transmission infrastructure. This infrastructure is necessary to ensure reliable service and, equally 

important, to open markets to competing suppliers of energy and thereby provide 

greater options for consumers. We have adopted a number of new rules in the last 

two years with this objective in mind, including rules providing incentives for the 

construction of new transmission, rules providing for long-term transmission rights, 

and rules strengthening regional planning of transmission. In addition to these generic actions, the Commission has taken a number of steps in the Northwest to increase supply options to consumers there, including Montana consumers. 

For example, last year the Commission adopted an innovative solution to transmission expansion by giving preliminary approval to develop the Montana-Alberta 
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73Montana-Alberta Tie, Ltd., 116 FERC Paragraph 61,071 (2006). 74 North Western Corporation, 117 FERC Paragraph 61,324 (2006). 

Tie, Ltd. (MATL) merchant transmission project.73 This 190-mile, 230 kV transmission line would extend from Lethbridge, Alberta to Great Falls, Montana, and 

would provide U.S. markets with their first electric interconnection with Alberta 

and up to 300 MW of power transfer capacity in each direction. The project sponsors 

stated that this new line would: (1) allow markets on both sides of the international 

border to have efficient and economic access to existing and new generation sources 

such as wind farms; (2) facilitate additional sources of generation; (3) provide additional transmission routes during tight supply situations; and (4) improve reliability 

in both the U.S. and Canada. All of the capacity on this line has been sold to newlydeveloping wind generators that will provide a source of clean, renewable energy, 

with a projected start in 2008. 

In another order last year, the Commission granted approval to a conceptual proposal from Northwestern for innovative pricing in support of a series of significant 

transmission expansions in Montana.74 One of these upgrades was to move an additional 184 MW of power from eastern to western Montana, a second upgrade was 

to move 550 MW of additional power from eastern to southwestern Montana, and 

a third upgrade was to move an additional 850 MW of power along the Montanato-Idaho border by strengthening the WECC Path 18 transmission corridor. Each 

upgrade was needed to alleviate transmission constraints in the affected areas. 

I also note that several of these projects, as well as the MATL project, were supported by Montana Governor Brian Schweitzer. 

Question 9. There is a difference between assuming that a competitive market 

could exist and demonstrating that one does exist to the public. How has a competitive market been demonstrated in Montana? 

Answer. I agree that the Commission cannot simply assume that a competitive 

market exists. The Commission does not rely solely on competition to assure just 

and reasonable prices; we rely on both competition and effective regulation. We 

must carefully consider whether there is sufficient competition to support market 

based rates and, even after granting market-based rates, closely monitor the market 

to protect against manipulation and abuse. Our approach towards assessing market 

power and the competitiveness of a market is modeled on the approach of antitrust 

agencies. I described in some detail in the answer to your question 1 our overall 

test for considering a market based rate application and the manner in which we 

applied that test in the case of PPL Montana. The case is now pending on rehearing 

and we will give close attention to the arguments of all the parties that have sought 

rehearing. 

RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR MENENDEZ

To begin, I would like to take the opportunity to respond to some of the questions 

you posed at my nomination hearing, in addition to your written questions. 

RELIABILITY PRICING MODEL

I share your concern that RPM actually contribute to new generation capacity to 

keep the lights on in New Jersey, rather than simply raising rates. I believe RPM 

includes a number of protections that further that goal. First, RPM allows prices 

to differ by location, thereby providing generation developers accurate price signals 

to locate where the generation is needed the most. The prior system did not have 

any such protections and, as a result, generation capacity was retired in New Jersey, where generation is most needed. Second, if the RPM auctions do not result 

in the needed increases in capacity, PJM will be required to conduct supplemental 

auctions to ensure there is adequate generation. Finally, we will closely monitor the 

implementation of RPM through a series of detailed reports and our continuing 

oversight of the market within PJM. If RPM does not live up to its objectives, I can 

assure you we will evaluate any necessary changes. I describe each of the foregoing 

protections in more detail below. 

RPM is aimed at addressing the long-term reliability needs of all electricity customers within the PJM Interconnection footprint, including New Jersey customers. 

In the past several years, due to (1) a surge in retirements by generators (2) steadily 

growing demand and (3) a slowdown of new entry, some areas within PJM started 

to experience reliability problems. Roughly 40 percent of the generator retirements 

since 2003 were located in New Jersey, which according to PJM is presently experiencing the highest number of reliability criteria violations of any state in the PJM 

footprint. New Jersey Board of Public Utilities Commissioner Butler, who represented the NJPBU at a February 3, 2006 Technical Conference on RPM, acknowl-
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75 Adjudicatory trial-type hearings typically take well over a year to complete, particularly in 

the case of a major merger. Section 1289 of EPAct 2005 revised FPA section 203 to require the 

Commission to ‘‘provide expedited review of such transactions’’, with action required within 180 

days after the application is filed unless the Commission finds, based on good cause, that an 

additional 180 days is needed for further consideration. Although the Exelon/PSEG merger was 

not reviewed under the Energy Policy Act of 2005, our order conditionally authorizing this merger was issued at almost the same time that EPAct 2005 was enacted. Thus, a Commission order 

instituting an adjudicatory trial-type hearing for this merger would have run counter to the time 

processing requirements that Congress was imposing on the Commission in the new energy legislation. 

edged this directly when he stated, ‘‘But let me at the outset say to you that we 

realize, we know there’s a problem. We in fact are ground zero of the problem, as 

has been mentioned several times today. We are doing some things that we think 

will help; we stand ready to implement whatever comes out of this process, because 

we don’t want the lights to go out, we don’t want to be the California, as it were, 

of the 21st Century, on the East Coast.’’ This view was widely shared by other participants in the technical conference. 

RPM was proposed to the Commission as the solution to these problems. The 

RPM proposal submitted to the Commission was the result of extensive settlement 

discussions conducted over 25 days involving more than 65 parties representing various PJM stakeholders. The RPM settlement garnered the support of the vast majority of the PJM stakeholders. The settlement replaces PJM’s existing daily capacity market with a three-year forward capacity market. A major advantage of the 

new approach is that it permits new entry to compete with existing capacity resources. It also establishes separate locational delivery areas to reflect existing 

transmission constraints; contains explicit provisions to prevent the exercise of market power through physical or economic withholding; and allows transmission and 

demand response to compete with existing and planned generation. 

Based on the evidence supplied by the parties, the RPM settlement is forecasted 

to enable PJM to meet its reliability obligations 95 percent of the time, as compared 

with a forecast of only 52.2 percent under its existing market structure. Evidence 

submitted by the parties also projects that the overall cost of the settlement provisions will be less than what would be incurred under PJM’s existing mechanisms. 

As to the issue of whether RPM will produce new generation, rather than just 

raising rates, I would note that the single PJM-wide capacity market did not 

produce market clearing prices sufficient to induce private investment in areas 

needing new generation, like New Jersey. Without locational pricing, the ability of 

the market to retain existing generating resources and to attract efficient investment will likely fall short of New Jersey’s needs and New Jersey will continue to 

experience reliability violations. For this reason, the Commission found in the December 22 Order that locational pricing is a just and reasonable means of providing 

the capacity prices that are needed to provide incentives for construction of necessary resources in the appropriate locations to achieve reliability. 

The settlement establishes a competitive market, with market power mitigation 

where needed, that will result in just and reasonable prices. Since RPM combines 

locational pricing with the three-year forward procurement and the variable resource requirement, it will improve reliability and lower overall costs to consumers. 

In addition, while RPM relies on market mechanisms to provide incentives for 

new entry, it also has a reliability backstop mechanism. Specifically, if PJM’s market is short for three consecutive delivery years, PJM’s Office of the Interconnection 

will declare a capacity shortage and make a filing with Commission for approval to 

conduct a reliability backstop auction. 

The settlement also promotes energy efficiency, in that greater price awareness 

is likely to incept users to (a) use energy more efficiently, and (b) become aware that 

they might benefit from participation in a demand response program. Energy efficiency programs implemented by the states have the potential to produce lower demand and thereby reduce capacity prices in RPM. The settlement also allows demand response to bid directly into the RPM auction, on a par with generation and 

transmission resources. 

Finally, I can assure you that the Commission will closely monitor the effectiveness of RPM, and will make modifications to the RPM rules, if necessary. 

EXELON/PSEG MERGER

The Commission did conduct a hearing before acting on the Exelon/PSEG merger. 

The Commission reviews all public utility mergers under section 203 of the Federal 

Power Act. It is well established that the Commission has discretion to hold either 

paper hearings or adjudicatory trial-type hearings.75 Paper hearings are the usual 
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practice at the Commission with respect to FPA section 203 proposals. The Commission held a paper hearing to consider the Exelon-PSEG merger, as acknowledged by 

the New Jersey Board of Public Utilities Chair Jeanne Fox, in her November 16, 

2006, letter to me. In this case, the paper hearing consisted of the application itself 

and five rounds of filings after the initial application was filed, including: (1) protests by more than twenty parties; (2) an answer by the applicants—including a proposal offering the divestiture of additional generation to address concerns raised by 

protesters; (3) the PJM Market Monitoring Unit’s study on the proposed merger’s 

effect on competition in PJM; (4) responses by protestors to the applicants’ answer 

and to the PJM Market Monitoring Unit’s study; and (5) the applicants’ further answer to protestors’ responses and comments on the PJM Market Monitoring Unit’s 

study. Altogether, the record of the Exelon-PSEG proceeding exceeded 2,000 pages, 

and the Commission considered the entire record, which is discussed in detail in the 

Commission’s 75-page order conditionally authorizing the merger. 

In order to address the merger’s potential effect on competition in the relevant 

geographic market—primarily New Jersey and Eastern Pennsylvania, the Commission required mitigation consisting of 2,600 megawatts of virtual nuclear divestiture 

(achieved through long-term energy sales from nuclear generating units) as well as 

the physical divestiture of 4,000 megawatts of fossil-fired capacity, including coalfired plants, combined-cycle natural gas generators and peaking facilities. The 

6,600-megawatt divestiture was, by far, the largest divestiture ever ordered by the 

Commission, and exceeded the divestiture required by the U.S. Department of Justice by nearly 1,000 megawatts. Not only did the Commission order that a large 

amount of generation be divested, but also that specific types of generation be divested so that the mitigation could be tailored to the indicated potential problems. 

Specifically, the Commission imposed divestiture all along the supply curve, from 

baseload to peaking units, in order address the merged firm’s ability and incentive 

to withhold output and potentially drive up the price of power in the relevant wholesale electricity markets. Had the merger proceeded, as a condition of the Commission’s authorization, Exelon would have been required to show that, given the actual 

plants that were divested and the buyers of those plants, the market concentration 

would be sufficiently reduced to mitigate any merger-related harm to competition. 

Finally, the Commission order accepted commitments that the merged parties’ 

transmission customers would be held harmless from any merger-related costs. And 

I also note that the applicants did not serve any wholesale requirements customers 

in New Jersey. 

Question 1. I welcome the opportunity to submit additional questions to you in 

writing. As I expressed at Thursday’s hearing, I continue to have grave concerns 

over some of the actions FERC has taken recently that affect New Jersey ratepayers. I hope to be convinced that FERC is doing its due diligence to fulfill its oversight role and protect New Jersey consumers to the fullest. I look forward to your 

answers on the following issues. Is the Commission taking any steps to ensure that 

the MMU’s daily activities are not being impeded as the Market Monitor has alleged? What steps does the Commission intend to take between today and the date 

of submission of the PJM investigation results to ensure that the MMU is able to 

conduct its daily monitoring and other tariff responsibilities? 

Answer. Yes, the Commission has taken several steps to ensure that the MMU’s 

daily activities are not being impeded as the Market Monitor has alleged. First, the 

Commission placed two complaints (one filed on April 17, 2007, as amended on April 

26, 2007, and one filed on April 23, 2007, as amended on April 30, 2007) alleging 

interference by PJM in the ability of the MMU to monitor the market, on what is 

called ‘‘fast track processing.’’ Accordingly, the Commission set accelerated comment 

deadlines of May 3 and April 30, and late motions for intervention were still being 

received on May 8. 

Next, this past week, the Commission issued an initial order with respect to the 

two complaints. This order consolidated the two dockets (EL07-56-000 and EL07-58-

000), granted late interventions, and issued data requests to both PJM and the 

MMU to determine whether there has in fact been any interference with the MMU 

by PJM, and whether any such interference is ongoing. This order was prompted 

in part because the record compiled to date includes conflicting assertions. The complaints allege that PJM had in the past interfered with the MMU’s ability to perform its functions, whereas PJM denies both past and ongoing interference. The 

Commission needs more information to ensure it has an adequate record to decide 

whether to grant relief, on an interim or long-term basis. The responses are due 

May 24, 2007, and the Commission intends to act promptly once it has reviewed 

them. 

Question 2. New York City is seeking to substantially increase its imports of electricity from New Jersey. This drain of power from New Jersey increases the risk 
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76PJM Interconnection, L.L.C., 117 FERC Paragraph 61,218 (2006). 

of major blackouts and other serious disruptions of electricity in the State. For example, the Neptune electric transmission line between Sayreville, NJ and Long Island will begin withdrawing 660 megawatts from New Jersey this summer, straining the grid’s ability to deliver power reliably to New Jersey; other projects in the 

works will withdraw more than an additional 2000 megawatts. The proposed extension cords would pull electricity out of New Jersey and there is no way to determine 

whether those electrons came from a power plant inside New Jersey or from elsewhere in PJM. As plugging the extension cords into the PJM system has essentially 

the same effect as a drastic growth in New Jersey’s demand for electricity, how does 

FERC plan to counteract the effect of these ‘‘extension cords’’ to New York, which 

reduce the city’s electricity costs at the expense of increased threats to electric reliability and higher prices in New Jersey? 

Answer. Steps have already been taken to ensure that the Neptune Project will 

not pose a reliability threat to New Jersey. In fact, when PJM, the organization in 

charge of reliability in the PJM footprint, approved the Neptune project as part of 

its planning process, it identified a series of upgrades to address any potential reliability concerns posed by the proposed Neptune Project. Some of these have already 

been constructed; others will be in service by the time Neptune starts operating. 

Moreover, the Commission has taken a series of actions that should enhance reliability generally within New Jersey. The Commission recently approved modifications to PJM’s annual Regional Transmission Expansion Plan (RTEP) to make 

transmission planning more forward-looking by expanding PJM’s planning horizon 

from 5 to 10 years and also expanding the scope of its economic planning process. 

In November 2006, the Commission approved an order, which allows PJM to review 

not only historical congestion data, but also to model congestion patterns using a 

variety of metrics primarily aimed at reducing overall production costs and lowering 

electric customers’ bills.76

In addition to an improved transmission planning process for PJM, the Commission has also recently approved an order that facilitates cost allocation for transmission projects identified as needed for either reliability or economic (congestionrelief) reasons. Specifically, in March 2007, the Commission approved PJM’s proposal to allocate the costs of new, centrally planned ‘‘backbone’’ transmission facilities operating at or above 500 kV—on a region-wide basis through a postage stamp 

rate. The Commission found that benefits from those assets are sufficiently broad 

that a rate that spreads the costs region wide is appropriate. 

In 2006 alone, a number of local transmission upgrades were approved to address 

reliability issues in New Jersey. Of significance, in order to mitigate anticipated 

generation retirements in northern New Jersey, several reconductoring projects 

were approved, including the Kittatiny-Newton 230 kV circuit. Additionally, other 

approved upgrades are intended to address voltage and baseline reliability issues. 

Major upgrades include the installation of a 600 MVAR reactive device support in 

the vicinity of Whippany, the addition of a fourth New Freedom 500/230 kV transformer, and the replacement of two 230/138 kV transformers at Roseland. Prior to 

2005, over $387 million of transmission upgrades were approved for New Jersey. 

PJM’s RTEP process offers a structure that assures consistent, equal opportunity 

across fuel types while flexible enough to adapt to specific technical realities and 

market challenges. Presently, PJM’s queues include interconnection requests in New 

Jersey for plants fueled by wind, hydro, biomass and methane. Some renewable energy sources such as wind, are recognized as intermittent resources. As such, their 

ability to generate power is directly and contemporaneously determined by their 

fuel. For example, wind turbines can generate electricity only when wind speed is 

within an established range. Obviously, these characteristics present challenges 

with respect to real-time operational dispatch and specific capacity value. To address the latter issue, PJM recently established an entire set of rules unique to 

intermittent renewable resources that provide for the determination of credible capacity values robust enough to recognize the summer peaking requirements of the 

PJM system. 

In addition to transmission, the Commission is working with PJM and its states 

on providing incentives for generation and demand response solutions to reliability 

and economic needs of the New Jersey customers. Of particular significance is the 

recently-approved Reliability Pricing Model (RPM) construct. Last year, more than 

65 parties representing various PJM stakeholders reached a settlement in the RPM 

proceeding that was widely supported. The settlement, which was approved by the 

Commission with some modifications, reforms PJM’s existing market rules to establish a forward market, which should encourage new entry. It establishes separate 

locational delivery areas to reflect existing transmission constraints. It prevents the 
121

exercise of market power through physical or economic withholding. It allows utilities to satisfy their energy needs through a combination of generation, transmission, 

and demand response. 

Question 3a. The USDOE has proposed to designate all of New Jersey, New York 

City and Long Island as part of a ‘‘National Interest Electric Transmission Corridor,’’ which would give the FERC authority to override state siting decisions on 

transmission lines and give private companies eminent domain authority. 

How will the FERC ensure that it grants no permits for additional ‘‘extension 

cords’’ to New York that adversely affect the reliability or price of electricity in New 

Jersey? 

Answer. The Commission’s review of any application for an electric transmission 

construction permit would be thorough and would evaluate regional impacts. To the 

extent there are concerns that a project will adversely affect New Jersey, the Commission will carefully consider such concerns in acting on any permit application. 

Before we can issue a construction permit, we are required to find that a proposed 

project will reduce transmission congestion and protect or benefit consumers, and 

is in the public interest. 

Question 3b. How will the FERC ensure that its permit decisions on transmission 

lines do not interfere with state efforts to implement more effective and less costly 

alternatives to address congestion, such as energy efficiency, demand response, and 

clean local electric generation? 

Answer. We are working closely with our colleagues at state agencies and with 

NARUC on those cost-effective alternatives to transmission congestion prior to any 

transmission line applications being received at the Commission. Last year, my 

state colleagues and I established a federal-state collaborative working group to develop more effective demand response. Further, Commission staff are available to 

consult and work with the states to achieve the goal of reducing congestion without 

having to resort to applications to site transmission at either the state or the federal 

level. This collaboration will be especially important in the area of demand response, the least expensive way to reduce congestion. If an application to site transmission ultimately is filed with the Commission, we intend to include the state 

agencies in all steps of the process, including our NEPA examination of alternatives. 

(123)

APPENDIX II 

Additional Material Submitted for the Record 

NATIONAL ASSOCIATION OF STATE FORESTERS, 

Washington, DC, May 9, 2007. 

Hon. JEFF BINGAMAN,

Chairman, Senate Energy & Natural Resources Committee, Washington DC. 

DEAR SENATOR BINGAMAN: On behalf of the National Association of State Foresters, we would like to express our strong support for the nomination of Mr. Lyle 

Laverty to become the Assistant Secretary of the Interior for Fish, Wildlife and 

Parks. A seasoned and experienced agency leader, with both the U.S. Forest Service 

and most recently with Colorado State Parks, this grounding will serve him well in 

the leadership capacity with the National Park Service, U.S. Fish & Wildlife Service 

and other Department of the Interior responsibilities. 

His handling of the wildfire issue is a perfect example of the tone, tenor and skills 

Mr. Laverty brings to this post. Mr. Laverty was one of the primary architects of 

the National Fire Plan which is a landscape scale, cross-boundary, partnership approach to address this nation’s wildfire problem. The collaborative foundation of the 

National Fire Plan led to the advent of the 10-year Comprehensive Strategy and Implementation Plan. These two plans are well recognized and often singled out for 

their successful all-lands, all-hands approach to wildfire and forest resource management issues. 

We have seen and experienced first-hand the successes related to Mr. Laverty’s 

partnership philosophies and believe that he will serve the interests of the nation 

with integrity built upon his years of successful field level natural resource management experience. 

Sincerely, 

E. AUSTIN SHORT, III, 

President, NASF and Delaware State Forester. 

RESERVEAMERICA, 

Ballston Spa, NY, May 7, 2007. 

Hon. JEFF BINGAMAN,

Chairman, Committee on Energy and Natural Resources, United States Senate, SD304, Washington, DC. 

DEAR SENATOR BINGAMAN: As President of ReserveAmerica, I’m writing to express 

my support for the nomination of Lyle Laverty to serve as the Assistant Secretary 

of the Interior for Fish and Wildlife and Parks. 

ReserveAmerica is the operator of the new federal recreation website, Recreation.gov. We are the reservations system contractor for the NRRS—the National 

Recreation Reservation System—which provides campground and day use reservations for more than 2,300 recreation facilities across the National Parks, National 

Forests, BLM, BUR, and Army Corps. 

Colorado State Parks has been a ReserveAmerica client since 1993. In Lyle’s role 

as Director of Parks he was consistently tough but fair. Speaking as a vendor and 

a member of the business community, Lyle was the best sort of client: he cared 

about his parks, he understood the world of business, and he pushed us hard to do 

better and delivery more for his staff and for the public. Under his leadership, and 

together with ReserveAmerica, Colorado significantly grew park reservations, making the park system more accessible to more families than ever before. 

If Lyle can use his knowledge of the parks business to help the National Parks 

in the same way he helped Colorado, then I am confident that the people of the 

United States will be well served by his leadership. 
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Speaking personally, I can also attest to Lyle’s leadership skills and consensusbuilding style. Successful public-private partnerships take work, understanding, and 

creativity on both sides, and Lyle and I haven’t always seen eye to eye. Where we’ve 

had our differences, we’ve trusted one another enough to iron them out to the benefit of Colorado’s State Parks. 

I urge the Senate Committee on Energy and Natural Resources to quickly confirm 

Lyle Laverty’s nomination. I’m certain that he will deal effectively with the many 

issues and challenges, especially related to visitation numbers, at America’s parks 

and wildlife areas. 

Regards, 

BRENDAN ROSS, 

President. 

NATIONAL PARK HOSPITALITY ASSOCIATION, 

May 8, 2007. 

Sen. JEFF BINGAMAN,

Chairman, Senate Energy &. Natural Resources Committee, 703 Senate Hart Building, Washington, DC. 

DEAR CHAIRMAN BINGAMAN: Please accept this endorsement on behalf of the National Park Hospitality Association (NPHA) on the confirmation of Mr. Lyle Laverty 

as Assistant Secretary of Fish, Wildlife, and Parks for the Department of the Interior. NPHA is trade association of businesses (concessioners and suppliers) providing facilities and services, such as lodging, restaurants, and a host of other services, to people visiting our National Parks and other federal lands. Concessioners 

have a long-standing relationship with the National Park Service and other federal 

land management agencies and serve a vital and beneficial function to the millions 

of people visiting our national parks and other recreation areas every year. 

We were pleased to hear of the announcement by President Bush to nominate 

Lyle Laverty as Assistant Secretary. Mr. Laverty has a long and distinguished 

record of public service and has served the nation well in his past employment in 

California, the Pacific Northwest, in Washington, D.C., and then in his position in 

Colorado. Because of his noted and outstanding career in public service, NPHA, 

without reservation, highly endorses Mr. Laverty to the Assistant Secretary position. 

We strongly urge the Senate Committee on Energy and Natural Resources to 

quickly and unanimously confirm Mr. Laverty’s nomination. We are confident that 

he will be an excellent addition to the Department of the Interior and will, among 

other things, help in resolving the many concerns and challenges facing America’s 

parks and wildlife refuge areas, 

Best Regards, 

TOD HULL, 

Executive Director. 

INTERNATIONAL SNOWMOBILE MANUFACTURERS ASSOCIATION, 

Haslett, MI, May 7, 2007. 

Hon. JEFF BINGAMAN,

Chairman, Committee on Energy and Natural Resources, SD-304, Washington, DC. 

DEAR SENATOR BINGAMAN: The International Snowmobile Manufacturers Association (ISMA) supports, the nomination of Lyle Laverty to serve as the Assistant Secretary of the Interior for Fish and Wildlife and Parks. The members of ISMA (Arctic 

Cat, BRP, Polaris, and Yamaha) urge the quick confirmation to fill an Important 

job which has been vacant for too long. 

The members of ISMA share an interest in encouraging Americans to enjoy the 

great outdoors when we feel it is most beautiful—in the winter. Snowmobiling is an 

activity that is enjoyed by millions of Americans who live in the snowbelt or travel 

to the snowbelt to enjoy all that winter has to offer. We believe it is especially important to encourage Americans to enjoy the outdoors in the winter when often 

times, people stay inside, gain weight, get lazy and become depressed. Snowmobiling 

offers an exuberant lifestyle change that causes snowmobilers to look forward to the 

winter. 

Snowmobiling is also an important part of the economic engine of rural America 

and Lyle Laverty understands the importance of snowmobiling to rural economies 

and to those who enjoy snowmobiling. 
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ISMA’s members and snowmobilers alike remember working with Lyle when he 

was with the U.S. Forest Service. Lyle was a joy to work with in developing partnerships and responsibly managing our public lands. Over the years, Lyle has demonstrated great leadership skills and an understanding of recreation activities and 

needs. We recently had the opportunity to work with Lyle in Colorado and he 

brought his national expertise to help us in improving our relationships in Colorado. 

We urge the Senate Committee on Energy and Natural Resources to quickly confirm Lyle Laverty’s nomination. I am certain that Lyle’s efforts in his new position 

will benefit all Americans. 

Sincerely, 

ED KLIM, 

President. 

PARTNERSHIP FOR THE NATIONAL TRAILS SYSTEM, 

Madison, WI, May 18, 2007. 

Hon. JEFF BINGAMAN,

Chairman, Senate Energy and Natural Resources Committee, Room 304, Dirksen 

Senate Office Building, Washington, DC. 

DEAR CHAIRMAN BINGAMAN: I am writing to recommend Lyle Laverty to serve as 

Assistant Secretary for Fish, Wildlife, and Parks in the Department of Interior. I 

have known Mr. Laverty in his roles as Director of Recreation and as Regional Forester for the U.S. Forest Service. 

I strongly support the nomination of Mr. Laverty to serve as Assistant Secretary 

for Fish, Wildlife, and Parks in the Department of Interior. His understanding of 

public land issues and his experience in balancing appropriate recreational and 

other use of public lands with the long term conservation and preservation of their 

resources and integrity will serve our country extremely well. He has demonstrated 

a fine appreciation of the benefits of and support for public-private collaboration and 

volunteerism in the stewardship of our national trails and other public land resources. 

I hope the Energy and Natural Resources Committee will recommend prompt confirmation of Lyle Laverty as Assistant Interior Secretary for Fish, Wildlife, and 

Parks. 

Sincerely, 

GARY WERNER, 

Executive Director. 

NEW MEXICO ENERGY, 

MINERALS AND NATURAL RESOURCES DEPARTMENT, 

Santa Fe, NM, May 7, 2007. 

Hon. JEFF BINGAMAN,

Chairman, Senate Committee on Energy and Natural Resources, 703 Hart Senate Office Building, Washington, DC. 

DEAR SENATOR BINGAMAN: I write in support of the nomination of Lyle Laverty 

as Assistant Secretary for Fish, Wildlife and Parks in the U.S. Department of the 

Interior (DOI). 

I have known and interacted professionally on public lands issues with Mr. 

Laverty for a number of years, first during his service with the U.S. Forest Service 

and more recently, as he has served as Director of Colorado State Parks. 

I always felt that Mr. Laverty was one of the more enlightened members of the 

Forest Service’s senior leadership. The Rocky Mountain region made strong efforts 

to improve wilderness, recreation, and interagency cooperative ecosystem management during his tenure, and he provided leadership in the Forest Service’s headquarters office as well. 

As Director of Colorado State Parks, Lyle has brought dynamic leadership to that 

agency, which I see evidence of, since Colorado is New Mexico’s close neighbor to 

the north and our state park agencies regularly interact. He is innovative, wellliked, and highly respected by his staff and among his peers within the National 

Association of State Park Directors. 
126

Lyle Laverty will bring to DOI outstanding experience and a solid commitment 

to protecting some of our nation’s most precious places and I urge the Senate to approve his nomination. Thank you for your consideration. 

Sincerely, 

DAVID J. SIMON, 

Director, New Mexico State Parks. 

NATIONAL ALLIANCE OF GATEWAY COMMUNITIES, 

Washington, DC, May 8, 2007. 

Hon. JEFF BINGAMAN,

Chairman, Senate Committee on Energy and Natural Resources, 304 Dirksen Senate 

Office Building, Washington, DC. 

DEAR MR. CHAIRMAN: The National Alliance of Gateway Communities (NAGC) 

would like to express its strong support for the nomination of Lyle Laverty as Assistant Secretary of Interior for Fish, Wildlife and Parks. 

The NAGC represents the interests of those communities that serve as gateways 

for millions of visitors to our national parks, forests and other Federal lands. These 

visitors and the commerce they generate are critical to the economic well-being of 

gateway communities. No one loves and respects these magnificent lands more than 

those who live and work in gateway communities. 

Our organization has known Lyle Laverty since it was formed nearly a decade 

ago. In fact, as then Associate Deputy Chief of the Forest Service, he supported the 

establishment of the NAGC because he recognized the importance of gateway communities and their strong, positive and cooperative relations with the Federal land 

agencies. 

Throughout his exceptional career with the Forest Service and as Director of Colorado State Parks for the past six years, Lyle has consistently demonstrated his passionate commitment to preserving the lands while serving those who use and enjoy 

them. His willingness to seek innovative solutions to public lands problems is renowned. He understands the need for cooperation and coordination between Federal, 

State and local entities and between the public and private sectors. We are confident he will bring these same skills and dedication to this new position. 

The NAGC gives him its highest endorsement as the next Assistant Secretary of 

Interior for Fish, Wildlife and Parks. 

Sincerely, 

BOB WARREN, 

Chairman, and General Manager, Shasta Cascade Wonderland Association. 

WESTERN STATES TOURISM POLICY COUNCIL, 

Bowie, MD, May 8, 2007. 

Hon. JEFF BINGAMAN, 

Chairman, Senate Committee on Energy and Natural Resources, 304 Dirksen Senate 

Office Building, Washington, DC. 

DEAR MR. CHAIRMAN: The Western States Tourism Policy Council (WSTPC) urges 

the Senate Energy and Natural Resources Committee to ratify the appointment of 

Lyle Laverty as the next Assistant Secretary of Interior for Fish, Wildlife and Parks. 

The WSTPC is a consortium of thirteen western state tourism offices, including 

the states of Alaska, Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Montana, Oregon, Utah and Wyoming. The mission of the 

WSTPC is to support public policies that enable tourism and recreation to have a 

maximum positive impact on the environment and economy of the West. 

The WSTPC has worked closely with Lyle Laverty during his distinguished career 

with the Forest Service and during his tenure as Colorado Director of State Parks. 

We have developed the utmost respect and appreciation for his talent and achievements as a result of these experiences. We have invited him to be a keynote speaker 

at three of our regional conferences dealing with public land issues and he has invariably inspired and challenged our conference attendees. 

The WSTPC knows that Lyle will serve with distinction and achievement as the 

next Assistant Secretary and we look forward to working with him in that capacity. 

Sincerely, 

AUBREY C. KING, 

Washington Representative. 
127

NATIONAL ASSOCIATION OF RV PARKS & CAMPGROUNDS, 

Falls Church, VA, May 9, 2007. 

Hon. JEFF BINGAMAN, 

Chairman, Committee of Energy & Natural Resources, United States Senate, Washington, DC. 

DEAR MR. CHAIRMAN: The National Association of RV Parks & Campgrounds 

(ARVC) is most pleased to vigorously support the nomination of Lyle Laverty to the 

position of Assistant Secretary of the Interior for Fish and Wildlife and Parks, overseeing the National Park Service and the U.S. Fish and Wildlife Service. 

ARVC has had a close and long standing working relationship with Mr. Laverty. 

We have always been impressed by his ability to build relationships with groups of 

different perspectives, his effective and open manner of communications and, most 

of all, with his creative problem solving and ability to seek out innovative ways to 

accomplish difficult or complex objectives. 

Mr. Laverty’s relationship with the private sector and his deep understanding and 

appreciation for the challenges of building and operating a small business are 

among his strongest qualities. 

We strongly recommend that your committee approve Mr. Laverty’s appointment 

to this important position. The nation will be well-served by having a man of his 

character and intellect in such a key position. 

Thank you for considering our views on this nomination. We look forward to 

learning of Mr. Laverty’s confirmation. 

Sincerely, 

LINDA L. PROFAIZER, 

President & CEO. 

AMERICAN RECREATION COALITION, 

Washington, DC, May 7, 2007. 

Hon. JEFF BINGAMAN, 

Chairman, Committee on Energy and Natural Resources, United States Senate, SD304, Washington, DC. 

DEAR SENATOR BINGAMAN: The American Recreation Coalition (ARC) is delighted 

to express our strong support for the nomination of Lyle Laverty to serve as the Assistant Secretary of the Interior for Fish and Wildlife and Parks. We urge his 

prompt and enthusiastic confirmation to fill an important job which has been vacant 

for too long—a job that should be playing a key role in protecting important natural, 

cultural and recreational resources and helping the nation’s public lands and waters 

contribute to the well-being and quality of life of every American. 

ARC represents a large number of diverse national recreation organizations. We 

share an interest in the nation’s public lands and waters, magnets for leisure time 

for Americans from every state, of every race and age, of all economic levels. And 

this makes the post of Assistant Secretary for Fish and Wildlife and Parks of vital 

concern to all ARC members. We have communicated to the Department of the Interior and the White House our concerns that this job, which includes guidance of the 

National Park Service and the U.S. Fish and Wildlife Service as well as oversight 

of key grant and technical assistance programs, is a priority and deserves an individual with broad knowledge of resource and recreation issues. 

We were thus delighted by the recent announcement of the President’s plan to 

nominate Lyle Laverty. Now a Coloradan whose work has significantly benefitted 

the many visitors to that state’s park system, Lyle has also served the nation well 

in California, the Pacific Northwest, and in Washington, D.C. Many ARC members 

recall favorably his national leadership of recreation and wilderness issues for the 

Forest Service in the 1980’s and early 1990’s, a time of burgeoning volunteerism, 

of exciting challenge cost-share projects and of new partnerships to manage and expand recreation opportunities. He played a role in shaping the national forest scenic 

byways program, the celebration of the 50th anniversary of the Smoky Bear program with its hot air balloon and the creation of WOW-Wonderful Outdoor World, 

which has taken more than 20,000 economically disadvantaged urban youth from 

around the nation on initial forays into the outdoors, including in-city camp-outs in 

Albuquerque. 

Throughout twenty years of communications and cooperation, Lyle has demonstrated to us a passion for youth, a commitment to protection of the shared legacy 

of the Great Outdoors and a zeal for partnerships and innovation. His recent efforts 

in Colorado are nationally recognized as guidelines for successfully confronting and 

reversing a decline in outdoor activity participation by American families and youth. 
128

He unites diverse, sometimes competing interests through his enthusiasm and because of the respect he has earned from environmental, conservation, recreation and 

rural development interests. In Colorado, he has played a central role at securing 

support for recreation facilities and programs from healthcare entities concerned 

about the challenges of obesity and inadequate physical activity. He has personally 

committed time and energy to complete the Continental Divide Trail, an effort that 

will benefit every state from New Mexico to Montana as well as millions of trail 

users from across the nation. 

We also applaud his involvement in service organizations, including Salvation 

Army, and his volunteer efforts through US AID in Lebanon and other nations. 

We urge the Senate Committee on Energy and Natural Resources to quickly and 

unanimously confirm Lyle Laverty’s nomination. We are certain that his work in 

that post will aid preparations for the centennial of the National Park Service and 

assist in resolving a variety of concerns now facing America’s parks and refuges. 

Warm regards. 

Sincerely, 

DERRICK A. CRANDALL, 

President. 

STATE OF WASHINGTON, 

WASHINGTON STATE PARKS AND RECREATION COMMISSION, 

Olympia, WA, May 7, 2007. 

Hon. PATTY MURRAY,

United States Senate, 173 Russell Senate Office Building, Washington, DC. 

DEAR SENATOR MURRAY: I am writing to inform you of the fine professional experience I’ve had with Lyle Laverty, a nominee for Assistant Secretary for Fish, Wildlife and Parks in the Department of the Interior. Mr. Laverty, the former Director 

of Colorado State Parks, and I served together for the last five years with the National Association of State Park Directors. 

Prior to his State Parks service, Mr. Laverty spent 30 years with the U.S. Forest 

Service, where he engaged many resource and public use issues relevant to that 

agency’s many transitions. After that service, Mr. Laverty was appointed Director 

of Colorado State Parks, for six years until this nomination. My affiliation with him 

in the national association conveyed a clear sense that as a leader, Mr. Laverty is 

aggressive and collaborative on tough tasks and open to innovation. He encourages 

and supports partnering to sustain park resources while providing them to the public in contemporary ways. 

I view Mr. Laverty to be an experienced and capable resource and recreation professional. Thank you for your consideration of his nomination. 

Sincerely, 

REX DERR, 

Director. 

THE LARGE PUBLIC POWER COUNCIL, 

Alexandria, VA, May 7, 2007. 

Hon. JEFF BINGAMAN, 

Chairman, United States Senate Committee on Energy and Natural Resources, 304 

Dirksen Senate Building, Washington, DC. 

DEAR SENATOR BINGAMAN: On behalf of the Large Public Power Council (LPPC), 

I am writing to express unqualified support for the re-nomination of Joseph T. 

Kelliher to the Federal Energy Regulatory Commission (FERC). The LPPC is an association of 24 of the nation’s largest state and municipally owned utilities. 

In his role as Chairman of FERC since July of 2006, and as a Commissioner since 

November, 2003, Commissioner Kelliher has been instrumental in restoring order 

to electric markets beset by uncertainty. Specifically, Chairman Kelliher and the 

Commission under his leadership have carried out their responsibilities for implementation of the Energy Policy Act of 2005 on time and in a manner that is faithful 

to Congressional intent. He has forged strong ties with State regulators whose cooperation is essential in protecting consumers and ensuring that electric and natural gas service meets our national needs. And, most importantly, he and his colleagues have worked together to make the Commission both a respected and effective federal regulatory agency. In particular, we believe his work and that of his colleagues in implementing the entirely new reliability provisions of the Energy Policy 
129

Act, while at the same time making much-needed improvements to the Commission’s landmark Order 888 open-access transmission rule, deserve particular credit. 

We have confidence in his ongoing leadership as FERC and the nation continue 

to find the appropriate balance between competition arid the need for ongoing regulation and oversight. For these reasons we recommend that the Committee advance 

his nomination to the Senate floor. 

Very truly yours, 

JOSEPH J. BEAL, P.E., 

LPPC Chair.

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