[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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36-883 WASHINGTON : 2007
_____________________________________________________________________________
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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
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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
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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
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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.
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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.
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\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.
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\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).
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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.
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\12\ Enron Power Marketing, Inc., 119 FERC 61,036 (April 11, 2007).
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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.
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\13\ Enron Power Marketing, Inc., Docket No. EL03-180-029 (order
issued April 25, 2007).
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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.
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\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\
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\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\
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\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.
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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.
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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).
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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.
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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.
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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
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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.