[Senate Hearing 110-97]
[From the U.S. Government Publishing Office]



                                                         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


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               COMMITTEE ON ENERGY AND NATURAL RESOURCES

                  JEFF BINGAMAN, New Mexico, Chairman

DANIEL K. AKAKA, Hawaii              PETE V. DOMENICI, New Mexico
BYRON L. DORGAN, North Dakota        LARRY E. CRAIG, Idaho
RON WYDEN, Oregon                    CRAIG THOMAS, Wyoming
TIM JOHNSON, South Dakota            LISA MURKOWSKI, Alaska
MARY L. LANDRIEU, Louisiana          RICHARD BURR, North Carolina
MARIA CANTWELL, Washington           JIM DeMINT, South Carolina
KEN SALAZAR, Colorado                BOB CORKER, Tennessee
ROBERT MENENDEZ, New Jersey          JEFF SESSIONS, Alabama
BLANCHE L. LINCOLN, Arkansas         GORDON H. SMITH, Oregon
BERNARD SANDERS, Vermont             JIM BUNNING, Kentucky
JON TESTER, Montana                  MEL MARTINEZ, Florida

                    Robert M. Simon, Staff Director
                      Sam E. Fowler, Chief Counsel
              Frank Macchiarola, Republican Staff Director
             Judith K. Pensabene, Republican Chief Counsel

                            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


                    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:]
    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 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.
    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 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 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 political 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.
    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.
    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 inter-connection 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.
    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 anti-manipulation 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.

                          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, 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 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, 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 approaching--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. 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 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.
    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.
    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----
    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.
    [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 
generation, 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.
    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.
    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 
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.
    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.
    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. 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, 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----
    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 consistent 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.
    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 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?
    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 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. 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 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 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 earthquakes 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 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 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.]


                               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 Government. 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 decisions 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 
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.
    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.''
    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.
---------------------------------------------------------------------------
    * Graphics and information have been retained in committee files.
---------------------------------------------------------------------------
    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          $420.00
     November:
    Estimated cost per visit: $70
    Estimated visits: 6
    Estimated costs..........................................
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.
    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 re-sale 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?
    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 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.
---------------------------------------------------------------------------
    * Information has been retained in committee files.
---------------------------------------------------------------------------
    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.
    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;
   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.
    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.
    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?
    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 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 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 non-power 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.
---------------------------------------------------------------------------
    \1\ Keyspan, 117 FERC Paragraph 61,080 (2006).
---------------------------------------------------------------------------
    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 market-based 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 public interest standard should apply. The 
U.S. Court of Appeals for the Ninth Circuit recently adopted that 
position.\2\
---------------------------------------------------------------------------
    \2\ Public 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).
---------------------------------------------------------------------------
    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 must-run contracts that significantly 
impact third parties.\5\
---------------------------------------------------------------------------
    \3\ Southern 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).
    \4\ Maine Bridgeport Energy, LLC, 118 FERC Paragraph 61,243 at P 
41-42 (2007).
    \5\ Maine Public Utilities Commission v. FERC, No. 05-1001 (D.C. 
Cir. June 30, 2006).
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    \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).
---------------------------------------------------------------------------
    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 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.

                      NEW TERMINALS APPROVED SINCE ENACTMENT OF EPACT 2005 (COMMISSION ONLY)
----------------------------------------------------------------------------------------------------------------
                                                 Storage
                                Deliverability   Capacity
      Company/LNG Project       (billion cubic   (billion      Docket No         Order Dates      Projected In-
                                 feet per day)    cubic                                           Service Date
                                                  feet)
----------------------------------------------------------------------------------------------------------------
Weaver's Cove Energy, LLC,              0.80         4.40  CPO4-36..........  07/15/05........  2010
 Fall River, MA.
Sempra Energy, Port Arthur              3.00        20.28  CP05-83..........  6/19/2006.......  Winter 2010
 Terminal Project, Port                                                                         Winter 2015
 Arthur, TX (Phase I & II).
Crown Landing LLC, Logan                1.20         9.20  CPO4-411.........  6/20/2006.......  4th Qt 2008
 Township, NJ.
Cheniere's Creole Trail LNG,            3.30        13.50  CP05-360.........  6/15/2006.......  Early 2009
 LP Creole Trail LNG Project,
 Cameron, LA.
Gulf LNG Energy, LLC,                   1.50         6.80  CP06-12..........  2/16/2007.......  Nov-09
 Pascagoula, MS.
Bayou Casotte Energy LLC,               1.30        10.10  CP05-420.........  2/16/2007.......  Mar-10
 Casotte Landing LNG Project,
 Pascagoula, MS.
                               ---------------------------------------------------------------------------------
      Total...................         11.10        64.28
----------------------------------------------------------------------------------------------------------------


                  TERMINAL EXPANSIONS APPROVED SINCE ENACTMENT OF EPACT 2005 (COMMISSION ONLY)
----------------------------------------------------------------------------------------------------------------
                                                 Storage
                                Deliverability   Capacity
      Company/LNG Project       (billion cubic   (billion      Docket No         Order Dates      Projected In-
                                 feet per day)    cubic                                           Service Date
                                                  feet)
----------------------------------------------------------------------------------------------------------------
Sabine Pass LNG, L.P., Sabine           1.40        10.10  CP05-396.........  6/15/2006.......  Apr-09
 Pass, LA (Phase II).
Freeport LNG Development,               2.50         3.40  CP05-361.........  9/26/2006.......  Winter 2009
 L.P., (Cheniere), Freeport,
 TX (Phase II).
Cameron LNG, LLC (LNG),                 1.15         3.40  CP06-422.........  1/18/2007.......  2010
 Hackberry LNG Terminal
 Expansion, Hackberry, LA.
Dominion Cove Point LNG, LP,            0.80         6.80  CP05-130 & 132...  6/15/2006.......  Sep-08
 Cove Point Expansion, Cove
 Point MD.
                               ---------------------------------------------------------------------------------
      Total...................          5.85        23.70
----------------------------------------------------------------------------------------------------------------


                            PENDING APPLICATIONS FOR NEW TERMINALS (COMMISSION ONLY)
----------------------------------------------------------------------------------------------------------------
                                                          Storage
                                         Deliverability   Capacity
          Company/LNG Project            (billion cubic   (billion        Docket No         Projected In-Service
                                          feet per day)    cubic                                    Date
                                                           feet)
----------------------------------------------------------------------------------------------------------------
Gulf Coast LNG Partners Project                  1.00         6.80  CP05-91..............  Winter 2009
 *Calhoun LNG, Port Lavaca, TX.
Sound Energy Solutions *(Mitsubishi),            0.70         3.50  CPO4-58..............  2009
 Long Beach LNG Terminal, Long Beach,
 CA.
Broadwater LNG *Long Island Sound, NY..          1.00         8.00  CP06-54..............  2010
Northern Star LNG--Northern Star                 1.00         6.80  CP06-365.............  2010
 Natural Gas, LLC, Bradwood, OR.
Quoddy Bay, LLC, Pleasant Point, ME....          2.00        10.10  CP07-38..............  2010
Downeast LNG, Inc, Robbinston, ME......          0.50         6.80  CP07-52..............  2010
Sparrows Point LNG, AES Sparrows Point           1.50        10.10  CP07-62..............  2010
 LNG, KKC, Baltimore, MD.
Jordan Cove Energy Project, L.P.,**              1.00         6.80  PF06-25..............  2010
 Jordan Cove LNG, Coos Bay, OR.
                                        ------------------------------------------------------------------------
      Total............................          8.70        58.90
----------------------------------------------------------------------------------------------------------------
* Draft Environmental Impact Statement issued.
** Pre-filing.


                                   PENDING APPLICATIONS FOR TERMINAL EXPANSION
----------------------------------------------------------------------------------------------------------------
                                                          Storage
                                         Deliverability   Capacity
          Company/LNG Project            (billion cubic   (billion        Docket No         Projected In-Service
                                          feet per day)    cubic                                    Date
                                                           feet)
----------------------------------------------------------------------------------------------------------------
Southern LNG (Elba Island Expansion              0.90         8.44  CP06-474.............  2010
 III), Elba Island, GA.                                                                    2012
----------------------------------------------------------------------------------------------------------------

    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 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 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;
          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.
    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\
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    \7\ See 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).
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    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 statement. 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 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 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.
---------------------------------------------------------------------------
    \8\ Verdant Power, LLC, 111 FERC Paragraph 61,024 (2005).
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    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 real-time 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 bid-based 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, 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/market-oversight.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, 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 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 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 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 open-access 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 
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/ft\2\-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, non-scheduled 
events, including safety-related incidents and security-related 
incidents, as soon as possible, but no later than within 24 hours. In 
addition, Commission staff 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\
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    \9\ See Distrigas Corporation v. FPC, 495 F.2d 1057 (1974).
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    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 on-shore facilities, the Coast Guard has regulatory 
authority over safety and security 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 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, 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.
---------------------------------------------------------------------------
    \10\ AquaEnergy Group, LTD, 102 FERC Paragraph 61,242 (2003).
    \11\ See, e.g., Presidential Proclamation No. 5928 (December 12, 
1988), 103 Stat. 2981 (asserting jurisdiction up to 12 nautical miles).
---------------------------------------------------------------------------
    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, 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 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.
---------------------------------------------------------------------------
    \12\ Enron Power Marketing, Inc., 119 FERC 61,036 (April 11, 2007).
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    \13\ Enron Power Marketing, Inc., Docket No. EL03-180-029 (order 
issued April 25, 2007).
---------------------------------------------------------------------------
    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 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-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 non-
jurisdictional 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 take-away capacity to get these much needed supplies 
to market. Additional pipeline 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 pre-filing 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/non-case specific rulemaking 
proceedings that the industry as a whole has drastically underinvested 
in transmission for decades. For instance, in Order No. 679\14\ at P 
10, the Commission stated:
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    \14\ Promoting Transmission Investment through Pricing Reform, 
Order No. 679, 71 FR 43294 (July 31, 2006), FERC Stats. & Regs. 
Paragraph 31,222 (2006).

           . . . 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\
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    \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).

    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.
    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\
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    \18\ See 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).
    \19\ See 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).
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    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\
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    \20\ See 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).
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    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.
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    \21\ Preventing 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.
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    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 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\
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    \22\ See Midwest Independent Transmission System Operator, Inc., 
117 FERC Paragraph 61,241 (2006), rehearing denied, 118 FERC Paragraph 
61, 208 (2007).
    \23\ See Midwest Independent Transmission System Operator, Inc., 
118 FERC Paragraph 61,209, rehearing pending (2007).
    \24\ PJM Interconnection, L.L.C., 119 FERC Paragraph 61,063 (2007).
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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\
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    \25\ Cal. Indep. Sys. Operator Corp., 99 FERC Paragraph 61,303 
(2002).
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    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\
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    \26\ See 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).
    \27\ PJM Interconnection, L.L.C., 117 FERC Paragraph 61,218, at P 
44 (2006), reh'g pending.
    \28\ See 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).
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    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.
---------------------------------------------------------------------------
    \29\ See 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/exp-study.pdf.
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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 be particularly attractive to new generating resources (e.g. 
intermittent) that are seeking project financing.\30\
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    \30\ Preventing 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.
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    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.
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    \31\ Standardization 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.
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    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\
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    \32\ California Independent System Operator Corporation, 119 FERC 
Paragraph 61,061 (2007)
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    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:

          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.
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    \33\ See, 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)
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    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\
---------------------------------------------------------------------------
    \34\ See 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).
    \35\ See 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).
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    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.
   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 cost-
effectiveness 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 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 hour-48 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 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 unit-specific 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 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 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 open-access 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\
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    \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.
    \37\ The members of Northern Tier include PacifiCorp, Idaho Power, 
Northwestern Energy, Utah Associated Municipal Power Systems, and 
Deseret Power.
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    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.
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    \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).
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    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 describing the 
nature and scope of the Commission's review, the Commission has 
explained that its review is limited and is appellate in nature:
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    \39\ 16 U.S.C.  839e(a)(2), (k) (2000).
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    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\
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    \40\ United States Department of Energy--Bonneville Power 
Administration, 80 FERC Paragraph 61,118 at 61,368-69 (1997) (footnotes 
omitted).
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    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\
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    \41\ See, 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).
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    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.
    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.
    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-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 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.
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    \42\ Public 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).
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    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 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.
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    \43\ Southern 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).
    \44\ Maine Public Utilities Commission v. FERC, No. 05-1001 (D.C. 
Cir. June 30, 2006).
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    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.
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    \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).
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    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 case-by-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-regulated 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\
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    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 market-based 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) market-based 
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 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 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.
---------------------------------------------------------------------------
    \47\ Loop 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.
---------------------------------------------------------------------------
    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 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 real-time 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.
---------------------------------------------------------------------------
    \48\ The $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).
---------------------------------------------------------------------------
    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.
---------------------------------------------------------------------------
    \49\ Order of Chief Judge Granting Minor Modification of Procedural 
Dates (March 12, 2007).

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                        Settlement                        Amount         Remaining
             Company                  Docket Nos.         Amounts       Amount Paid      Disbursed    Escrow Balance  Receivable Due        Status
--------------------------------------------------------------------------------------------------------------------------------------------------------
American Electric Power Service   EL03-137-000......       45,240.00       45,240.00  ..............       45,240.00  ..............  Paid in Full
 Corporation.
City of Redding, California.....  EL03-149-000, EL03-       6,300.00        6,300.00  ..............        6,300.00  ..............  Paid in Full
                                   182-000.
Colorado River Commission of      EL03-184-000......      996,145.00      996,145.00  ..............      996,145.00  ..............  Paid in Full
 Nevada.
Duke Energy North America, LLC..  INO3-10-000, PA02-    2,500,000.00    2,500,000.00    2,450,713.58       49,286.42  ..............  Paid in Full
                                   2-000.
Duke Energy North America, LLC..  PA02-2-000........       57,441.84       57,441.84  ..............       57,441.84  ..............  Paid in Full
Duke Energy Trading and           EL03-152-000......      549,973.00      549,973.00  ..............      549,973.00  ..............  Paid in Full
 Marketing, LLC.
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./     EL00-95-000, EL00-    1,329,332.11    1,329,332.11  ..............    1,329,332.11  ..............  Paid in Full
 West Cost Power, Inc./Segundo     98-000, EL01-10-
 Power LLC/Long Beach              000, INO3-10-000,
 Generation, LLC/ Cabrillo         PA02-2-000.
 Power, LLC.
El Paso Electric/Enron Power      EL02-113-000, EL03-  32,528,766.00  ..............  ..............  ..............   32,528,766.00  Rehearing Pending
 Marketing.                        180-000, EL03-154-
                                   000.
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
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 Pending
Reliant Energy Services, Inc....  EL03-59-000, INO3-   50,000,000.00   50,000,000.00   44,183,754.64    5,816,245.36  ..............  Paid in Full
                                   10-000, PA02-2-
                                   000.
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          EL00-95-000, EL00-      760,333.00      760,333.00  ..............      760,333.00  ..............  Paid in Full
 Corporation.                      98-000.
TOTAL...........................  95,635,836.95.....   63,089,978.95   46,634,468.22   16,455,510.73   32,545,858.00
--------------------------------------------------------------------------------------------------------------------------------------------------------

    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 Enron-Trial 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     Recovery   Estimated
                                        Value     (Percent)    Recovery
------------------------------------------------------------------------
Enron Unsecured Claim..............        875      \50\ 35        306
Enron Subordinated Claim...........        600            0          0
Enron Unsecured Claim to Salt River          2.7         35          0.9
 Project...........................
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.
---------------------------------------------------------------------------
    \50\ See 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.
    \51\ See, for example, Form 8-K, Mirant Corp., December 15, 2005.
---------------------------------------------------------------------------
    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. 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 FERC-jurisdictional 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 Mobile-Sierra 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 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.
---------------------------------------------------------------------------
    \52\ Public 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).
    \53\ Pub. Util. Dist. No. 1 v. FERC, 471 F.3d 1053, 1061 (9th Cir. 
2006), 471 F.3d at 1061.
---------------------------------------------------------------------------
    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:
---------------------------------------------------------------------------
    \54\ Californians for Renewable Energy, Inc. v. California Public 
Utilities Commission,--119 FERC 61,058 (April 10, 2007).

          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 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 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. 
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 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.
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    \55\ See California Independent System Operator Corp., 119 FERC 
Paragraph 61,061 (2007).
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    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 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\
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    \56\ See Montana Alberta Tie, Ltd., 116 FERC 61,071 (2006).
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    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 market-based 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 Commission-filed 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 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.
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    \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 applicant's 
market presence. The snapshot in time approach is used to prevent 
applicants from manipulating study results based on speculative 
potential future events.
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    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.
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    \58\ For 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.
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    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.
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    \59\ These 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.
    \60\ PPL Montana, LLC, 115 FERC Paragraph 61,204 at 41 (2006). 
April 14 Order at 105.
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    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 
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\
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    \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).
    \62\ For 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.
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    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.
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    \65\ PPL 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.
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    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.
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    \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.
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    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?
    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 long-term 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.
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    \68\ April 14 Order at 110.
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    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\
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    \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.'').
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    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.
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    \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.
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    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 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.
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    \72\ For purposes of the indicative screens the only markets first-
tier to the study area are considered for potential supplies to be 
imported.
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    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 market-based 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 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 newly-developing wind generators that will 
provide a source of clean, renewable energy, with a projected start in 
2008.
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    \73\ Montana-Alberta Tie, Ltd., 116 FERC Paragraph 61,071 (2006).
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    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 Montana-to-
Idaho border by strengthening the WECC Path 18 transmission corridor. 
Each upgrade was needed to alleviate transmission constraints in the 
affected areas.
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    \74\ North Western Corporation, 117 FERC Paragraph 61,324 (2006).
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    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, acknowledged 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 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.
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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.
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    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 
coal-fired 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 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\
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    \76\ PJM Interconnection, L.L.C., 117 FERC Paragraph 61,218 (2006).
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    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 (congestion-relief) 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 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.

                              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, SD-304, 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.
    Speaking personally, I can also attest to Lyle's leadership skills 
and consensus-building 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.
    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, well-liked, and highly respected 
by his staff and among his peers within the National Association of 
State Park Directors.
    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.
                                 ______
                                 
            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, SD-304, 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. 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 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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