[House Hearing, 107 Congress]
[From the U.S. Government Publishing Office]



 
          NATURAL GAS INFRASTRUCTURE AND CAPACITY CONSTRAINTS
=======================================================================

                                HEARING

                               before the

                 SUBCOMMITTEE ON ENERGY POLICY, NATURAL
                    RESOURCES AND REGULATORY AFFAIRS

                                 of the

                              COMMITTEE ON
                           GOVERNMENT REFORM

                        HOUSE OF REPRESENTATIVES

                      ONE HUNDRED SEVENTH CONGRESS

                             FIRST SESSION

                               __________

                            OCTOBER 16, 2001

                               __________

                           Serial No. 107-126

                               __________

       Printed for the use of the Committee on Government Reform


  Available via the World Wide Web: http://www.gpo.gov/congress/house
                      http://www.house.gov/reform






                          U.S. GOVERNMENT PRINTING OFFICE
82-547                             WASHINGTON : 2002
_____________________________________________________________________________
For Sale by the Superintendent of Documents, U.S. Government Printing Office
Internet: bookstore.gpo.gov  Phone: toll free (866) 512-1800; (202) 512-1800  
Fax: (202) 512-2250 Mail: Stop SSOP, Washington, DC 20402-0001






                     COMMITTEE ON GOVERNMENT REFORM

                     DAN BURTON, Indiana, Chairman
BENJAMIN A. GILMAN, New York         HENRY A. WAXMAN, California
CONSTANCE A. MORELLA, Maryland       TOM LANTOS, California
CHRISTOPHER SHAYS, Connecticut       MAJOR R. OWENS, New York
ILEANA ROS-LEHTINEN, Florida         EDOLPHUS TOWNS, New York
JOHN M. McHUGH, New York             PAUL E. KANJORSKI, Pennsylvania
STEPHEN HORN, California             PATSY T. MINK, Hawaii
JOHN L. MICA, Florida                CAROLYN B. MALONEY, New York
THOMAS M. DAVIS, Virginia            ELEANOR HOLMES NORTON, Washington, 
MARK E. SOUDER, Indiana                  DC
STEVEN C. LaTOURETTE, Ohio           ELIJAH E. CUMMINGS, Maryland
BOB BARR, Georgia                    DENNIS J. KUCINICH, Ohio
DAN MILLER, Florida                  ROD R. BLAGOJEVICH, Illinois
DOUG OSE, California                 DANNY K. DAVIS, Illinois
RON LEWIS, Kentucky                  JOHN F. TIERNEY, Massachusetts
JO ANN DAVIS, Virginia               JIM TURNER, Texas
TODD RUSSELL PLATTS, Pennsylvania    THOMAS H. ALLEN, Maine
DAVE WELDON, Florida                 JANICE D. SCHAKOWSKY, Illinois
CHRIS CANNON, Utah                   WM. LACY CLAY, Missouri
ADAM H. PUTNAM, Florida              DIANE E. WATSON, California
C.L. ``BUTCH'' OTTER, Idaho          ------ ------
EDWARD L. SCHROCK, Virginia                      ------
JOHN J. DUNCAN, Jr., Tennessee       BERNARD SANDERS, Vermont 
------ ------                            (Independent)


                      Kevin Binger, Staff Director
                 Daniel R. Moll, Deputy Staff Director
                     James C. Wilson, Chief Counsel
                     Robert A. Briggs, Chief Clerk
                 Phil Schiliro, Minority Staff Director

Subcommittee on Energy Policy, Natural Resources and Regulatory Affairs

                     DOUG OSE, California, Chairman
C.L. ``BUTCH'' OTTER, Idaho          JOHN F. TIERNEY, Massachusetts
CHRISTOPHER SHAYS, Connecticut       TOM LANTOS, California
JOHN M. McHUGH, New York             EDOLPHUS TOWNS, New York
STEVEN C. LaTOURETTE, Ohio           PATSY T. MINK, Hawaii
CHRIS CANNON, Utah                   DENNIS J. KUCINICH, Ohio
JOHN J. DUNCAN, Jr., Tennessee       ROD R. BLAGOJEVICH, Illinois
------ ------

                               Ex Officio

DAN BURTON, Indiana                  HENRY A. WAXMAN, California
                       Dan Skopec, Staff Director
               Connie Lausten, Professional Staff Member
                        Regina McAllister, Clerk
           Paul Weinerger, Minority Professional Staff Member
                            C O N T E N T S

                              ----------                              
                                                                   Page
Hearing held on October 16, 2001.................................     1
Statement of:
    Carpenter, Paul R., principal, Brattle Group; Professor 
      Joseph Kalt, John F. Kennedy School of Government, Harvard 
      University; Paul Amirault, vice president, marketing, Wild 
      Goose Storage, Inc.; and Gay Friedmann, senior vice 
      president, legislative affairs, Interstate Natural Gas 
      Association of America.....................................    89
    Lorenz, Lad, director, capacity and operational planning, 
      Southern California Gas Co.................................    56
    Lynch, Loretta, president, California Public Utilities 
      Commission.................................................    29
    Moore, Michal, Commissioner, California Energy Commission....    46
    Wood, Patrick, III, Chairman, Federal Energy Regulatory 
      Commission.................................................     9
Letters, statements, etc., submitted for the record by:
    Amirault, Paul, vice president, marketing, Wild Goose 
      Storage, Inc., prepared statement of.......................   124
    Carpenter, Paul R., principal, Brattle Group, prepared 
      statement of...............................................    92
    Friedmann, Gay, senior vice president, legislative affairs, 
      Interstate Natural Gas Association of America:
        Major projects pending...................................   156
        Prepared statement of....................................   134
    Kalt, Professor Joseph, John F. Kennedy School of Government, 
      Harvard University, prepared statement of..................   106
    Lorenz, Lad, director, capacity and operational planning, 
      Southern California Gas Co., prepared statement of.........    58
    Lynch, Loretta, president, California Public Utilities 
      Commission, prepared statement of..........................    31
    Moore, Michal, Commissioner, California Energy Commission, 
      prepared statement of......................................    48
    Ose, Hon. Doug, a Representative in Congress from the State 
      of California:
        Historical Daily Spot Gas Prices.........................    69
        Prepared statement of....................................     2
    Waxman, Hon. Henry A., a Representative in Congress from the 
      State of California, prepared statement of.................     7
    Wood, Patrick, III, Chairman, Federal Energy Regulatory 
      Commission, prepared statement of..........................    11


          NATURAL GAS INFRASTRUCTURE AND CAPACITY CONSTRAINTS

                              ----------                              


                       TUESDAY, OCTOBER 16, 2001

                  House of Representatives,
  Subcommittee on Energy Policy, Natural Resources 
                            and Regulatory Affairs,
                            Committee on Government Reform,
                                                    Washington, DC.
    The subcommittee met, pursuant to notice, at 12 p.m., in 
room 2154, Rayburn House Office Building, Hon. Doug Ose 
(chairman of the subcommittee) presiding.
    Present: Representatives Ose, Shays, and Kucinich.
    Staff present: Dan Skopec, staff director; Barbara Kahlow, 
deputy staff director; Connie Lausten, professional staff 
member; Regina McAllister, clerk; Phil Barnett, minority chief 
counsel; Paul Weinerger, minority counsel; and Jean Gosa, 
minority assistant clerk.
    Mr. Ose. Good afternoon. Welcome to today's hearing of the 
Energy Policy, Natural Resources and Regulatory Affairs 
Subcommittee. I'm going to dispense with my opening statement 
and just submit it to the record.
    I would yield to Mr. Waxman accordingly.
    [The prepared statement of Hon. Doug Ose follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.001
    
    [GRAPHIC] [TIFF OMITTED] 82547.002
    
    [GRAPHIC] [TIFF OMITTED] 82547.003
    
    Mr. Waxman. Thank you very much, Mr. Chairman. This hearing 
addresses a crucial energy issue: the price and availability of 
natural gas. I hope it will shine a spotlight on one of the 
root causes of the Western energy crisis, the exorbitant 
natural gas prices that prevailed in California from the fall 
of 2000 to the spring of 2001.
    In the year prior to June 2000, when the energy crisis 
started, electricity prices in California averaged around $36 
per megawatt hour. By early 2001, they were averaging $300 to 
$400 per megawatt hour, a 150fold increase. After spending $7 
billion in electricity in 1999 California spent $27 billion in 
2000, and has already spent $23 billion in the first 8 months 
of 2001.
    The results have been devastating. One of the California's 
three major utilities, PG&E, filed for bankruptcy. The State's 
bond rating was downgraded. Hundreds of thousands of jobs may 
have been lost.
    As I investigated this issue, I learned that natural gas 
played a central role in causing electricity prices to soar. 
Like electricity prices, gas prices in California, particularly 
southern California, skyrocketed. When prices peaked in 
December 2000, natural gas was selling at the wellhead in Texas 
for $10.50 per million BTU. The border price at southern 
California, however, reached almost $60 per million BTU. Prices 
remained high in the first 5 months of 2001. And on May 8, 
2001, for example, gas from the Permian producing basin that 
sold in Chicago for around $4.37 was selling at the California 
border for $12.55.
    These expensive gas prices were used to justify high 
wholesale electricity prices, according to FERC Commissioner 
William Massey, when FERC set the so-called proxy clearing 
price for electricity this past February at $430 per megawatt, 
roughly $350 of that amount, over 80 percent of the price, was 
natural gas for an inefficient generator.
    One of the key issues for California is whether market 
manipulation played a role in the State's high gas prices. 
Allegations of market manipulation have focused on El Paso 
Natural Gas Co., which owns the pipeline system that transports 
natural gas from the Southwest to California. Last week a FERC 
administrative law judge found that while El Paso and its 
marketing affiliate, El Paso Merchant Energy, ``had the ability 
to exercise market power,'' it is, ``not at all clear that they 
in fact exercised market power.''
    The judge did find that there was blatant collusion between 
the affiliates in the awarding of pipeline contracts. After 
reviewing transcripts of taped conversations in which El Paso 
Merchant asked for and received a secret discount from El Paso 
Natural Gas, the judge said, ``If that's not hanky panky, 
there's no such thing as hanky panky.''
    The issue is now before the FERC Commissioners for a final 
decision. There is considerable evidence that suggests that the 
El Paso affiliates did manipulate the natural gas market in 
California. Beginning in March 2000, El Paso Natural Gas sold 
over a third of its pipeline capacity to El Paso Merchant. Soon 
after the contract began, natural gas prices at the California 
border began to rise.
    The rise in gas prices correspond with remarkably low 
levels of capacity usage by El Paso Merchant. As Paul Carpenter 
points out in his testimony, from March through October 2000, 
El Paso used just 44 percent of its pipeline capacity, at the 
same time as other large shippers on El Paso were using well 
over 80 percent of their capacity. As a result, California 
entered the crucial winter heating season with critically low 
levels of stored gas.
    El Paso Merchant lost its stranglehold on the pipeline on 
May 31, 2001. Almost immediately thereafter, natural gas prices 
in California began to drop. Gas prices at the southern 
California border were around $10 per million BTU on May 31st. 
By June 8th they had dropped to around $3.50.
    I urge Chairman Wood, who is here today, and his colleagues 
at FERC to carefully consider this evidence of market 
manipulation as they make their final decision in the El Paso 
case.
    A second key issue is what FERC can do to prevent market 
manipulation in the future. The El Paso example shows that 
pipeline affiliates with the ability to exercise market power 
routinely and illegally shared information with each other. 
FERC needs to ensure that such abuses do not recur and that the 
market for natural gas remain fair and competitive.
    These are important issues. They affect the pocketbook and 
livelihood of millions of Americans in the West and throughout 
the Nation. I hope today's hearing will provide some additional 
insight into their resolution.
    Mr. Chairman, I thank you very much for holding this 
hearing.
    Mr. Ose. Thank you, Mr. Waxman.
    [The prepared statement of Hon. Henry A. Waxman follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.004
    
    [GRAPHIC] [TIFF OMITTED] 82547.005
    
    Mr. Ose. Mr. Shays, do you have an opening statement?
    Mr. Shays. Mr. Chairman, I don't, but I thank you for 
having this hearing.
    Mr. Ose. We're going to go ahead to the witness testimonies 
now. I want to remind the witnesses that we received your 
written testimony. I know Mr. Waxman's people have read it, and 
I have personally read the testimony, so we'll give you each 5 
minutes to summarize. You don't need to go through the entire 
thing. Just hit the high points, because we are on a bit of a 
limited time.
    The ordinary course of business in this committee is we 
swear in our witnesses. So I would like the first panel and the 
second panel, to the extent they're here, to rise and take the 
oath.
    [Witnesses sworn.]
    Mr. Ose. Let the record show all the witnesses answered in 
the affirmative.
    Our first witness today is Chairman of the Federal Energy 
Regulatory Commission, Mr. Pat Wood. Mr. Wood, for 5 minutes.

    STATEMENT OF PATRICK WOOD III, CHAIRMAN, FEDERAL ENERGY 
                     REGULATORY COMMISSION

    Mr. Wood. Thank you, Chairman Ose, Mr. Waxman, Mr. Shays. 
The importance of natural gas in our Nation's power future just 
cannot be overplayed. I think the desirability of gas, not only 
as a domestic fuel but as an environmentally friendly fuel, in 
addition to the economics of natural gas and the economics of 
natural gas generation technology make it really the fuel of 
choice.
    I think one of the important things that the FERC has to 
do, and certainly the focus of this hearing and of the 
testimony of my colleagues here and of the second panel is the 
importance of getting the gas to the electric generators so 
that the markets work well on the electric side. Of course, it 
goes without saying that getting gas to the gas consumer, 
whether that's a large industrial or small residential 
consumer, is equally important.
    So we have to, on the regulatory side of the fence, make 
sure that there's sufficient infrastructure to get the gas from 
all parts of the continent to all customers on the continent.
    I think in the last 10 years as the Commission has moved 
toward more of a market-based rate regulation system and more 
of a contract-oriented certification system, which definitely 
moves away from the world we used to live in, the report card, 
by and large, has been pretty positive. That has yielded 
significant consumer benefits across the years. There has been 
significant investment made in natural gas pipeline facilities 
and natural gas production and the associated liquids and other 
types of production that goes on near the wellhead.
    That's not to say it's perfect. I think the focus of this 
hearing is what's happened in California, particularly in the 
southern half of the State over the last year. I might indicate 
there's certainly a shortfall of the market system as it works 
today in concert with State and Federal regulatory and 
environmental regimes to deliver this commodity to the public.
    I take with good advice Mr. Waxman's recommendations and 
assure him and the committee that our Commission will look 
completely and thoroughly at the record of the El Paso case, as 
we do of other cases. But it is important to get that one 
right. We will do it fairly and based on the record.
    And I should add, in looking forward, it's important that 
any ambiguities in the Commission's current rules no longer 
exist. And I'm pleased to inform the committee that in our last 
meeting in September, we voted to publish for comment revisions 
to our gas and electric affiliate rules--they were stand-alone 
in the past--that integrate the two into one combined code of 
conduct and also knock out a lot of the loopholes and tighten 
up the language.
    For those who are willing to play in the market in good 
faith, these rules should provide no different regime than what 
we had before. For those who may want to test the limits of 
what's right or wrong, I think these rules will come as an 
unwelcome surprise. I look forward to finalizing those rules in 
the near future.
    I want to just focus on one particular piece of data that I 
didn't have and that we didn't have in my original testimony 
but I think is useful. The staff is in the process now of 
putting together an assessment of all the infrastructure issues 
in the West, both gas and electric and hydroelectric, to try to 
work with our fellow regulators and the western Governors and 
the industry out west. But one of the things that came out of 
this was this chart that's up on the side here.
    Mr. Ose. Just a moment. Can we turn that chart? Perhaps the 
Members of Congress would like to see it, too. Thank you.
    Mr. Wood. The blue at the bottom is the hydroelectricity as 
a percentage of the total for California. This is just power 
generated within the State. California also imports up to 25 
percent capacity, particularly in the summer. That's not shown 
here. This is just the consumption and the generation within 
the State of California on an annual average.
    The lower three numbers are gigawatt hours, which is a unit 
of measure for how much energy is actually generated in the 
State. What it shows largely is that hydro, for the reasons we 
all know, that the drought coming out there, has dropped off 
these last 2 years of the cycle. Other, which would be coal and 
some renewables, primarily thermal, has increased modestly over 
that time period. But the middle number, natural gas, has not 
only increased in real number, but as a percentage of the 
total.
    I think it's helpful to understand that, you know, this is 
a pretty significant ramp-up of demand for just the electric 
power industry in a very short period of time, and even the 
best planned systems would be stressed out by this.
    So I think both Loretta and Michael will talk about some of 
the actions the State has taken on the infrastructure side 
certainly, recently, to try to keep up with that, as well as 
what I have reported in my testimony about what FERC has done. 
But I just wanted to kind of show this is a pretty dramatic 
change from probably one quarter to over one half of the 
gigawatt hours in a given year, in just a 4-year time span, has 
shifted to natural gas usage.
    That concludes my testimony.
    Mr. Ose. Thank you, Mr. Wood.
    [The prepared statement of Mr. Wood follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.006
    
    [GRAPHIC] [TIFF OMITTED] 82547.007
    
    [GRAPHIC] [TIFF OMITTED] 82547.008
    
    [GRAPHIC] [TIFF OMITTED] 82547.009
    
    [GRAPHIC] [TIFF OMITTED] 82547.010
    
    [GRAPHIC] [TIFF OMITTED] 82547.011
    
    [GRAPHIC] [TIFF OMITTED] 82547.012
    
    [GRAPHIC] [TIFF OMITTED] 82547.013
    
    [GRAPHIC] [TIFF OMITTED] 82547.014
    
    [GRAPHIC] [TIFF OMITTED] 82547.015
    
    [GRAPHIC] [TIFF OMITTED] 82547.016
    
    [GRAPHIC] [TIFF OMITTED] 82547.017
    
    [GRAPHIC] [TIFF OMITTED] 82547.018
    
    [GRAPHIC] [TIFF OMITTED] 82547.019
    
    [GRAPHIC] [TIFF OMITTED] 82547.020
    
    [GRAPHIC] [TIFF OMITTED] 82547.021
    
    [GRAPHIC] [TIFF OMITTED] 82547.022
    
    [GRAPHIC] [TIFF OMITTED] 82547.023
    
    Mr. Ose. Joining us also is the President of the California 
Public Utilities Commission, Ms. Loretta Lynch. You're 
recognized for 5 minutes.

   STATEMENT OF LORETTA LYNCH, PRESIDENT, CALIFORNIA PUBLIC 
                      UTILITIES COMMISSION

    Ms. Lynch. Thank you, Mr. Ose, Mr. Waxman, Mr. Shays. My 
testimony addresses three primary themes.
    First, California looks to the Federal Energy Regulatory 
Commission to define and enforce clear standards for 
determining when market power exists in the natural gas market 
and also when it's exercised in the interstate natural gas 
markets.
    Second, a so-called mismatch in intrastate and interstate 
capacity was not and could not have been a factor in last 
year's high California border prices for natural gas.
    And, finally, the facts demonstrate that California's 
intrastate capacity has been and, despite the increase in 
electric generation generated from natural gas, continues to be 
more than adequate to accommodate the State's natural gas 
demands.
    Rather, the California Public Utilities Commission submits 
that last year's extraordinarily high natural gas prices 
resulted largely from the illegal exercise of market power on 
an interstate pipeline, not inadequate intrastate 
infrastructure. And that is precisely the reason that we look 
to FERC now to both remedy past wrongs and to define and 
enforce a clear standard for market power abuse.
    In fact, California relies on one of four methods that have 
been established by the FERC to acquire and transport natural 
gas over the interstate systems to our in-State utility systems 
at the border. As California discovered only too clearly this 
past winter in an unhealthy natural gas market where market 
power is being exercised, the normally adequate options 
collapsed with disastrous consequences. Last winter, California 
endured natural gas border prices double those faced by the 
rest of the Nation, and at times those prices climbed to levels 
seven to eight times the national average. The cost to 
Californians ran into the tens of millions of dollars both for 
higher natural gas costs and for higher electric costs driven 
by the high gas costs on the margin.
    Thus, the FERC has a golden opportunity now in the pending 
decision before it in our complaint against El Paso Pipeline 
and its marketing affiliate, to both provide a remedy for past 
illegal actions and also to prevent future price spikes by 
defining clear standards for identifying market power where it 
occurs in the interstate markets and also in preventing its 
exercise.
    Some parties have put forward the inaccurate theory that 
California's natural gas infrastructure is inadequate and that 
lack of infrastructure caused last year's price increases. 
However, an accurate understanding of the California 
infrastructure and its operation, I believe, leads inescapably 
to the conclusion that a so-called capacity mismatch cannot 
have been a factor in last year's border price increases. 
California utilities do not build their systems to match the 
delivery capacity of the interstate pipelines, as those 
interstate pipelines suggest that they should. Rather, 
California's gas utilities build the natural gas infrastructure 
to reliably meet anticipated demand of their California 
customers at a reasonable cost. Overbuilding means price 
increases to California's businesses and families.
    Considering Southern California Gas's actual operation of 
its system and the PUC's actions over the last 10 years, 
interstate take-away capacity into southern California actually 
exceeds the certificated interstate capacity into southern 
California. Further, it's critical to know that at the other 
California points where nominal intrastate capacity is less 
than the nominal delivered interstate capacity, the intrastate 
pipeline has more than enough capacity to take the full volumes 
at the point of interconnection.
    Despite continuing high utilization of transmission 
capacity into southern California, California border prices 
have declined dramatically since May, when El Paso's contract 
with its affiliate expired. Even during the high natural gas 
demand driven by this past summer's air-conditioning needs, 
PG&E, SoCalGas and San Diego Gas & Electric combined all 
continued to meet all their customers' needs. California's gas 
utilities have met these needs even as they transported 
additional gas through their system to inject gas into storage 
for this winter's heating reserves. The PUC had required the 
utilities to overinject, to make sure that what happened last 
year would not happen this year in terms of inadequate storage. 
And now those levels are 20 to 30 percent higher than this time 
last year.
    But California has not stopped there. Over the last year, 
the PUC has worked with the California natural gas utilities to 
identify and implement a number of strategic infrastructure 
expansions across the State. Those expansions are listed in my 
written testimony and they show that we will add 455 million 
cubic feet of capacity a day of intrastate capacity by the end 
of this year, which is an unprecedented expansion that added a 
full 10 percent to southern California's gas capacity.
    These and other potential intrastate expansions we're 
considering also will help the State to benefit from some of 
the interstate pipelines that FERC is currently considering. 
Basically, California has been vigilant in managing the 
evolution of its in-State infrastructure to match changing 
patterns of demand. But California needs its approach of 
careful vigilance to be matched at the Federal level as well.
    Mr. Ose. Thank you, Ms. Lynch.
    [The prepared statement of Ms. Lynch follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.024
    
    [GRAPHIC] [TIFF OMITTED] 82547.025
    
    [GRAPHIC] [TIFF OMITTED] 82547.026
    
    [GRAPHIC] [TIFF OMITTED] 82547.027
    
    [GRAPHIC] [TIFF OMITTED] 82547.028
    
    [GRAPHIC] [TIFF OMITTED] 82547.029
    
    [GRAPHIC] [TIFF OMITTED] 82547.030
    
    [GRAPHIC] [TIFF OMITTED] 82547.031
    
    [GRAPHIC] [TIFF OMITTED] 82547.032
    
    [GRAPHIC] [TIFF OMITTED] 82547.033
    
    [GRAPHIC] [TIFF OMITTED] 82547.034
    
    [GRAPHIC] [TIFF OMITTED] 82547.035
    
    [GRAPHIC] [TIFF OMITTED] 82547.036
    
    [GRAPHIC] [TIFF OMITTED] 82547.037
    
    [GRAPHIC] [TIFF OMITTED] 82547.038
    
    Mr. Ose. Also joining us today is the commissioner from the 
California Energy Commission, Mr. Michael Moore, who has 
prepared a rather comprehensive report which we have read. Mr. 
Moore, you're recognized for 5 minutes.

  STATEMENT OF MICHAL MOORE, COMMISSIONER, CALIFORNIA ENERGY 
                           COMMISSION

    Mr. Moore. Thank you, Mr. Chairman, Mr. Waxman, Mr. Shays. 
It's a great privilege to be here. I thank you very much for 
the opportunity. I am Michael Moore. I am an economist by 
trade, and I occupy that seat on the California Energy 
Commission. And in that position, I oversee data collection, 
market structure issues, and the electricity and natural gas 
issues in terms of reporting or information generation for the 
State.
    In that role, we did produce a report called ``Natural Gas 
Infrastructure Issues,'' which has been vetted quite widely and 
is the subject of many comments from a lot of different 
parties. You have summaries of it in my prepared testimony, but 
I'd like to go to four of the major conclusions and 
recommendations, then highlight them as we proceed here today.
    First, I'd like to point out that when reviewing market 
conditions that affect California in establishing new rules and 
procedures, the FERC should take into account the fact that 
California lies at the end of a long and rather narrow 
corridor. Upstream demand claims on gas can be disruptive and 
introduce volatility in the California market, and I believe 
that my colleagues at FERC should be very cognizant of the 
impact that can have when they're establishing their new rules 
and oversight.
    Second, we're subject to weather permutations in the West, 
and what happens in the Northwest, for instance, can 
dramatically affect the State. Shifts which emphasize generator 
demand for natural gas doubled demand in some periods and 
produced a secondary planning peak that was unforeseen in the 
past and which has to be accommodated in terms of planning 
backbone infrastructure expansion within the State. We've been 
using the wrong model, and it's time for us to move to 
accommodate a new model which is more realistic.
    Third, slack capacity both in the intrastate and interstate 
system is very important, needs to be built into all of our 
calculations. We suggest, and I believe we have broad 
concurrence in this, that 15 to 20 percent is the right amount 
of slack capacity that will allow some gas-on-gas competition 
and provide a more open and transparent market as we go 
forward.
    And fourth, we very much support the market monitoring 
activities that have been proposed by Chairman Wood, and we 
would like to cooperate in those. We have a great deal of 
expertise and talent at our disposal. We plan to use that in 
conducting new hearings and workshops in the near future, which 
we will initially use to produce a risk assessment of the gas 
system where we literally test it, at least mathematically, and 
test it in public in our hearings and make that information 
available to our colleagues and to the PUC and also at the 
FERC. We hope that in the expansion of the market monitoring 
activities that the FERC undertakes they'll utilize the 
experience and talent at the State and use it to augment and 
bolster their own reporting.
    Mr. Chairman, I believe that the other observations that 
we've made about the market are pretty well known by now, but 
we did not take on the question of price manipulation. We very 
specifically stayed away from that. It's not in our purview. As 
a consequence, we didn't comment on it. But we did comment on 
the likelihood that there were different series of events that 
could have affected the market, and you'll find those in our 
summary.
    Thank you for allowing me to come.
    [The prepared statement of Mr. Moore follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.039
    
    [GRAPHIC] [TIFF OMITTED] 82547.040
    
    [GRAPHIC] [TIFF OMITTED] 82547.041
    
    [GRAPHIC] [TIFF OMITTED] 82547.042
    
    [GRAPHIC] [TIFF OMITTED] 82547.043
    
    [GRAPHIC] [TIFF OMITTED] 82547.044
    
    [GRAPHIC] [TIFF OMITTED] 82547.045
    
    [GRAPHIC] [TIFF OMITTED] 82547.046
    
    Mr. Ose. Thank you, Mr. Moore.
    Our final witness on the first panel is Lad Lorenz who is 
the director of capacity and operational planning for Southern 
California Gas Co. Welcome. You're recognized for 5 minutes.

  STATEMENT OF LAD LORENZ, DIRECTOR, CAPACITY AND OPERATIONAL 
             PLANNING, SOUTHERN CALIFORNIA GAS CO.

    Mr. Lorenz. Thank you, Chairman Ose, and members of the 
committee. I appreciate the invitation to testify regarding the 
important issue of California's natural gas infrastructure. I 
understand that there have been some challenges to the adequacy 
of the intrastate transportation system in southern California. 
I want to try and clear up some of the misperceptions.
    Let me state from the outset that despite any allegations 
to the contrary, the SoCalGas pipeline system has adequate 
infrastructure, both pipeline capacity and storage capacity, to 
meet the needs of its customers. In fact, last year when we 
faced unprecedented record demand for gas, the SoCalGas system 
operated at an overall 87 percent load factor. That means that 
despite these record high demands the SoCalGas system still had 
available our slack capacity.
    What caused that record high demand on the SoCal system? 
There were a series of events almost analogous to a perfect 
storm that created the record high gas demand. Are those events 
likely to repeat themselves? We think it's unlikely, but 
nonetheless the SoCal system was adequate to meet even that 
demand, with some capacity to spare. We haven't curtailed any 
customers, firm or interruptible, on the SoCalGas system for 
over 10 years.
    To maintain our strong commitment to reliable service, we 
are undertaking some key expansions to our system at the 
California/Arizona border in Kern County, south of Bakersfield, 
and in western San Bernadino County near Victorville. These 
expansions are going to add 11 percent to our capacity; 375 
million a day of new backbone capacity is being created, and 
this will ensure that the system continues to have adequate 
capacity to meet the needs of our customers and provide an 
adequate level of slack capacity.
    In light of this information, you may wonder what all the 
fuss is about, why questions regarding the adequacy of our 
system have arisen. The key issue looking forward is the 
expected significant increase in natural gas demand from new 
electric power plants being constructed throughout the western 
United States. What are the implications of these new power 
plants for gas infrastructure systems in the West, and 
particularly for the SoCalGas system?
    First, most of these new power plants are planned for 
outside of southern California and off the SoCalGas system. Of 
the 72,000-plus megawatts of announced new power plants, only 
about 9,300 megawatts, or 13 percent, are proposed even for 
location in southern California. While it's not expected that 
all of these new power plants will actually get built, it's 
telling to note that of the 27,000 megawatts of new power 
plants that are currently under construction in the WSCC, only 
about 2,900 megawatts, or less than 10 percent, are located in 
southern California. Because the new out-of-state power plants 
will export power to California and are more efficient than the 
existing units served by the SoCalGas system, we project an 
overall decline in gas demand and capacity utilization for the 
SoCalGas infrastructure. Not one new baseload power plant has 
yet signed up to take service directly from the SoCalGas 
system.
    How will those new out-of-state power plants be served? 
Through direct connection to the expanded interstate pipeline 
system. The new interstate pipelines argue that our 
infrastructure is inadequate. Clearly, that is not the case. 
What the interstates want is for intrastate utility systems 
like SoCalGas to expand their take-away capacity solely to have 
somewhere to dump excess supplies when the new electric 
generation customers are not operating. But that safety net for 
the interstate pipelines would cause a huge cost to California 
consumers without regard to whether or how often that capacity 
would actually be utilized.
    Putting pipe in the ground is an expensive proposition and 
one that we don't take lightly. Ramifications of overbuilding 
our intrastate system are too great for our customers. The 
question is how much slack capacity and who is going to pay for 
it. The pipeline expansions on the SoCalGas system that I and 
Commissioner Lynch have mentioned earlier ensure that we will 
be able to maintain the 15 to 20 percent slack capacity that 
Commissioner Moore mentioned on the SoCalGas system. We believe 
that's the appropriate amount for our system and for our 
customers.
    Congress has sought to address the confusion and 
controversy between FERC and the States regarding the need for 
pipeline infrastructure, and we think that's a valuable effort. 
Any solutions must consider what demand growth is expected, 
where that demand is expected to occur, whether the current 
infrastructure can serve that current and forecasted demand, 
and how planned expansions compare to each other and with 
anticipated growth.
    As you can see, I don't believe there's any truth to the 
charges that SoCalGas is unwilling to build new pipeline or 
expand its system. Clearly, we will expand our system when 
there is a market and it is in the interest of our customers. 
The SoCalGas system has adequate capacity to meet the needs of 
its customers. And, without additional demand on the system or 
long-term contractual commitments for capacity, it doesn't make 
sense to build more capacity on our system. Thank you.
    Mr. Ose. Thank you, Mr. Lorenz.
    [The prepared statement of Mr. Lorenz follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.047
    
    [GRAPHIC] [TIFF OMITTED] 82547.048
    
    [GRAPHIC] [TIFF OMITTED] 82547.049
    
    [GRAPHIC] [TIFF OMITTED] 82547.050
    
    [GRAPHIC] [TIFF OMITTED] 82547.051
    
    [GRAPHIC] [TIFF OMITTED] 82547.052
    
    Mr. Ose. Many of you have testified in front of Congress 
before. Those little boxes in front of you have a green, yellow 
and red light. The green light denotes that we're in the first 
4 minutes of a 5-minute period. The yellow light indicates that 
you're in the last minute. The red light means stop. Now we're 
going to go around the panel here through 5-minute question 
periods. You'll probably have a variety of questions because I 
know that the questions in the Northeast, for instance, may be 
a little bit different than the questions for the Pacific 
Coast. I'm going to go ahead and take 5 minutes. So if you'll 
start the clock.
    Mr. Wood and the others, you have varying opinions as to 
whether or not there is a surplus or a deficit of capacity on 
the interstate lines going into California? I just want to make 
sure I get a yes or a no answer.
    Mr. Wood, is there a deficit of interstate capacity going 
into California for transmission of natural gas?
    Mr. Wood. Is there a deficit today?
    Mr. Ose. Yes.
    Mr. Wood. Yes.
    Mr. Ose. Ms. Lynch.
    Ms. Lynch. I think we have all we need as long as we 
incorporate storage and in-state capacity.
    Mr. Ose. Mr. Moore.
    Mr. Moore. I think the conditions are tight. I think 
depending on the day and the demand, you could describe it 
either way, but it's tight enough to reveal either case.
    Mr. Ose. Mr. Lorenz.
    Mr. Lorenz. There is adequate capacity in the SoCalGas 
system to meet even unexpected demands like we had last year.
    Mr. Ose. All right. My second question has to do with how 
people acquire capacity on the line to transmit or convey gas 
from point A to California. I'm confused a little bit when I 
talk with staff about the manner in which people acquire 
capacity, and I'm hopeful you can help me. Apparently, there 
are two different systems by which capacity is allocated on the 
lines going into southern California versus the lines going 
into northern California? Am I accurate on that, Mr. Wood?
    Mr. Wood. I might have to defer on that one. There are 
traditional ways to get transportation. There are numerous ways 
to get interruptible or shorter-term transportation. As far as 
the interstate lines going into the State, that regime should 
largely be the same, whether it's the south or the north.
    Mr. Ose. Is it the same, though?
    Mr. Wood. Well, the El Paso one has a little bit different 
history. I think the opinion that Mr. Waxman pointed to is 
probably the best way to teach that. But El Paso's about in the 
middle of a 10-year settlement as to its rates and terms. The 
nature of some of the rates on the El Paso is different than 
they are on Pacific Gas going into California for some 
customers, historically grandfathered customers, that have, I 
think, what is properly characterized as more expansive rights 
to use firm capacity on the system than a newer customer might 
have.
    Mr. Ose. FERC controls the nomination process on the 
interstate lines. Maybe my question is more properly directed 
to one of the three of you. Who controls the nomination process 
on the intrastate lines?
    Ms. Lynch. On intrastate it's the Public Utilities 
Commission.
    Mr. Ose. OK. Is the nomination process for firm capacity 
the same in the North as it is in the South?
    Ms. Lynch. We have slightly different systems in the North 
and the South depending primarily on how PG&E has used its 
system and prior Commission decisions versus how Southern 
California Gas uses its system. We have before us now the 
question of changing, to what extent to change the overall 
process of pricing in the South.
    Mr. Ose. There's something before the PUC right now to look 
at that.
    Ms. Lynch. Correct.
    Mr. Ose. OK. Mr. Lorenz, Southern California Gas Controls 
apparently has this pleading in front of the PUC. Can you just 
give me a layman's explanation of the nomination process--
you're smiling--on SoCalGas's capacity right now.
    Mr. Lorenz. It would be complicated Congressman, but I will 
try.
    Mr. Ose. We've only got a minute. We can come back to it on 
the second round if you like.
    Mr. Lorenz. On the interstate pipeline system parties 
subscribe for and hold long-term capacity commitments. Then 
customers on the SoCalGas system have contracts with us for 
service and they're on all volumetric rates. Customers nominate 
deliveries on our system, then we confirm those nominations to 
the upstream interstate pipelines. It's that nomination and 
confirmation process that determines which gas will flow and 
also how gas gets cut.
    So it is a complicated process, but it's a matching of 
nominations on the SoCalGas system with nominations on the 
interstate pipeline system.
    Mr. Ose. So the end user actually contracts for gas on both 
the interstate line and the intrastate line.
    Mr. Lorenz. That's correct.
    Mr. Ose. And apparently the system you're using for 
nomination purposes is different than what's used, for 
instance, on PG&E's lines.
    Mr. Lorenz. No, the process is exactly the same. But on the 
PG&E system, there is an unbundled backbone intrastate 
transmission system, that provides firm receipt point rights 
into the PG&E system. We have proposed a similar structure in 
southern California to the CPUC, but it has not yet been acted 
upon. So we don't have firm receipt point rights on the 
SoCalGas system like PG&E does in northern California.
    Mr. Ose. I want to come back to this question, but my time 
has expired. Mr. Waxman for 5 minutes.
    Mr. Waxman. Thank you, Mr. Chairman.
    Ms. Lynch, I'd like to walk through with you the key 
allegations against El Paso. I'm going to start with the 
awarding of the El Paso contract in the spring of 2000. The 
administrative law judge's decision quotes directly from 
telephone transcripts the conversations between El Paso Natural 
Gas and El Paso Merchant, which demonstrate blatant collusion 
to keep secret a discount for service on the El Paso pipeline. 
This deal gave El Paso Merchant an unfair advantage during the 
bidding season when it bid for the entire block of pipeline 
capacity that El Paso was auctioning off. In fact, the judge 
found that there was a general sharing of information between 
the affiliates in violation of the FERC standards of conduct.
    Ms. Lynch, can you tell us how the collusion between the El 
Paso affiliates allowed them to exercise market power?
    Ms. Lynch. Well, basically if the affiliates have inside 
information that other sellers or other bidders don't have, 
then they have superior information to be able to bid the price 
up or profit from that. So it's essentially inside information 
that in that context, for instance, in front of the Securities 
and Exchange Commission, it would never be allowed, because 
then it's not a fair market. So if the affiliate has in essence 
illegal information, they then can profit handsomely to the 
detriment of both--all the other participants in the market and 
also California consumers.
    Mr. Waxman. The El Paso contract ran for 15 months starting 
in March 2000. The PUC presented evidence indicating that 
during the summer and fall of 2000, El Paso Merchant used a 
fraction of its available pipeline capacity to deliver gas to 
California. While other shippers on the El Paso pipeline were 
using 80 to 90 percent of their available capacity, El Paso 
Merchant used less than 50 percent of its available capacity.
    Ms. Lynch, how significant was El Paso's decision to use a 
fraction of its capacity?
    Ms. Lynch. It was quite significant, because that meant 
that there wasn't gas available in that pipeline because the 
affiliate was holding it back. I'm not remembering the exact 
percentage, but I believe it's about 40 percent of the total 
capacity on that pipeline was controlled by the affiliate. So 
if they're not using it, that means all of a sudden there's an 
artificial shortage which will raise prices, and then that has 
a ripple effect throughout the entire California gas market.
    Mr. Waxman. Did El Paso's actions affect storage of gas in 
southern California?
    Ms. Lynch. Absolutely. As the prices rose last summer, many 
of the utilities, as well as other purchasers, electric 
generators, saw that there was an unusual rise in prices, 
expected that price to go down after the summer peak, so 
therefore in the summer of 2000 did not buy gas to inject into 
storage and were caught short in the winter of 2000 because 
they didn't buy gas to inject. The price rose dramatically to 
10 times what it had been the year before, and they didn't have 
gas in storage to use.
    Mr. Waxman. California gas prices began to rise in the 
summer of 2000, hit record heights in the winter of 2000, 2001. 
It is only after the El Paso contract expired on May 31, 2001 
that prices in California began to decline. Why did gas prices 
in California start to go down after the El Paso contract 
expired?
    Ms. Lynch. We believe that gas prices went down because now 
there were many sellers who could use the capacity that was 
being withheld by the El Paso affiliate. So instead of a one-
to-one relationship where that one seller got illegal 
information, many sellers then could compete appropriately. 
And, frankly, one of the reasons that went down because FERC, 
with the addition of new commissioners including Commissioner 
Wood, then allowed our Commission, the PUC, to put on its 
evidence. Until then, we were not allowed to even show our 
evidence. And I think that hearing, that allowing of the 
hearing, gave El Paso a signal. They dropped their collusive 
contract and the market became more competitive.
    Mr. Waxman. So to sum up, the judge found that there was 
blatant collusion between El Paso affiliates, which gave them 
the ability to exercise market power. The result, according to 
the judge, was tremendous profits for El Paso Merchant, at 
least $148 million.
    Ms. Lynch, given the collusion between the El Paso 
affiliates, given their ability to exercise market power, given 
El Paso's decision to use so little of its capacity, how did 
the judge conclude that there was not clear evidence of market 
manipulation? And do you agree with the administrative law 
judge's decision?
    Ms. Lynch. Well, the administrative law judge came to the 
brink of allowing refunds for Californians and then stepped 
back. I believe that stepping back was not consistent with FERC 
precedent which would show that in periods of high demand the 
FERC needs to look very carefully at whether market power that 
is available, as the ALJ found it was, was in fact exercised. 
So although this is in front of Mr. Wood and his colleagues, I 
hope that they look very carefully at the evidence, including 
the evidence under seal, which I believe does establish 
California's case for refunds.
    Mr. Waxman. Mr. Wood, I know it wouldn't be proper for you 
to comment on all this, but I'd like to underscore the 
seriousness of these allegations. As I mentioned, the 
administrative law judge's decisionmakes some troubling 
findings, and despite these findings the judge found it is not 
at all clear that El Paso in fact exercised market power. It 
seems to mean that, right or wrong, these allegations deserve a 
better answer than it's not clear. Now it is, of course, up to 
you. Thank you, Mr. Chairman.
    Mr. Ose. Thank you Mr. Waxman. I'll use my time for that. 
Mr. Shays for 5 minutes.
    Mr. Shays. Mr. Chairman, I'm happy to have both of you go 
another round because I am going to be talking about things 
that are more important, like what's happening in New England, 
So I'll let the less important issues go forward. So I'm going 
to just pass this time and take the second round.
    Mr. Ose. Where is New England?
    Mr. Waxman. East of Sacramento.
    Mr. Ose. East of Sacramento. That's a small part of the 
country. I want to followup with Mr. Waxman's comment. I want 
to make sure I'm clear. The June 1st decision that you 
referenced, we have evidence here that indicates that the price 
dynamic was actually broken on May 29th, following adoption of 
FERC's market mitigation plan which would have been prior to 
the June 1st date that you just cited.
    This is a data chart of the prices for the past, from May 
to October, at the five entry points for natural gas. We're 
going to enter this into the record. I think it is important to 
understand exactly the chronology here.
    I want to go back to Mr. Lorenz on something. This 
nomination process for capacity on your line, is the current 
system helpful or hurtful or is there a competitive advantage 
or disadvantage? Why are you seeking a change in the nomination 
process that you use?
    [The information referred to follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.053
    
    [GRAPHIC] [TIFF OMITTED] 82547.054
    
    Mr. Lorenz. It is very important for customers to have the 
ability to acquire firm rights on the local transmission system 
and that's what we're proposing. That would allow customers to 
have assurance not only with regard to the volumes that they're 
delivering but the point at which those volumes are going to be 
delivered and received into the SoCalGas system. Right now, our 
system is utilized in total without any specific firm rights 
that can be acquired by parties. And so the reliability of 
supplies at a particular receipt point are always in question. 
With a system of firm receipt point rights, then customers can 
be guaranteed of receiving the gas volumes that they want at 
the point that they want them delivered. In other words, having 
access to the supply bases that they're choosing to acquire 
their gas at.
    Mr. Ose. Is one of the things that you're attempting to 
address in the filing you have before PUC whether or not 
someone is a core or a non-core customer? In other words, do 
they have interruptible or non-interruptible gas?
    Mr. Lorenz. The proposal we made to the CPUC always has 
provisions that provide for firm capacity on behalf of the core 
market. They are our primary customers. But we think it's 
important for noncore customers to also have access to firm 
capacity if they choose that.
    Mr. Ose. I think that strikes right at the comment you made 
earlier about 13 percent of the generating capacity or the 
proposed generating capacity only being built in the southern 
California area. Is it the uncertainty of a firm delivery 
ability of natural gas that is an impediment here that you're 
attempting to address?
    Mr. Lorenz. I think yes, that is one of the factors that 
we're trying to address, that reliability is important for 
electric generation customers. We're competing vigorously with 
the interstate pipelines for new power plants in southern 
California. We believe we offer a competitive product with 
superior services, balancing services and storage services that 
interstate pipelines can't offer. But there has been rate 
uncertainty, there has been delivery uncertainty, and there has 
been long-term contracting uncertainties and we're trying to 
address those through a variety of proposals to the PUC.
    Mr. Ose. If I understand your point, then, the competition 
on the interstate pipelines is that perhaps out-of-state and 
interstate pipelines will deliver directly to a facility a firm 
commitment for natural gas in such and such a volume for their 
generating facility, and then they'll burn that fuel to 
generate the electricity and then send it over high voltage 
lines into California. The choice is whether to build in, say, 
Arizona or in southern California.
    Mr. Lorenz. That's certainly one of the issues that's being 
addressed. And, of course, it's the issue of natural gas 
transmission capacity versus electric transmission capacity.
    Mr. Ose. Right. Ms. Lynch, in terms of Southern California 
Gas's filing, do you have any idea--is it agendaed? What's the 
timetable for looking at it?
    Ms. Lynch. We have a significant piece. It was on our 
agenda for October 25th. My colleague, Commissioner Bilas, is 
the assigned commissioner and has, I believe, has just put out 
a proposed decision last week regarding the structuring of 
that.
    Mr. Ose. So it's moving forward.
    Ms. Lynch. It's moving forward. I hope to have that decided 
by the end of the year.
    Mr. Ose. Mr. Waxman for 5 minutes.
    Mr. Waxman. Thank you, Mr. Chairman. Mr. Moore, the 
California Energy Commission's natural gas report makes it an 
interesting and important finding, and I want to quote it:

    The deregulation of electric generation in California 
contributed to the high prices of natural gas compared to the 
rest of the United States. The deregulation scheme adopted by 
California required all the Merchant power plants to bid into a 
spot market. When drought conditions were experienced and 
generation supply became tight, the Merchant power plants were 
able to set the price for electricity. Knowing they would 
receive whatever price necessary to cover their costs, the 
Merchant generators became indifferent to the price of natural 
gas. This dynamic was a major contributor to the 
extraordinarily high natural gas prices.

    Mr. Moore, do you agree that the ability of generators to 
name their price was a major contributor to California's high 
natural gas prices?
    Mr. Moore. I think it contributed to it and I believe that 
the ability of the generators during that period literally to 
walk past what might have been considered reasonable market 
behavior, and to exercise what would at least on the surface 
appear to be some degree of market power, certainly contributed 
to that. I think that the gas market responded predictably when 
the generators were willing to pay, with indifference almost, 
any price that they wanted.
    Mr. Waxman. Ms. Lynch, do you agree?
    Ms. Lynch. Absolutely. They just passed it right through, 
or tried to.
    Mr. Waxman. What's your view, Commissioner Wood?
    Mr. Wood. I think it's hard to argue with the fact that as 
the CEC report pointed out, Mr. Waxman, that as the last user 
of gas, the electric generator in that market as it was set up 
last year really did not have an incentive on their side to 
manage the upside risk of the price, because it really could be 
transferred to the--well, at that point the host utility, and 
then later the DWR. So yes, there was really no incentive in a 
market that is really driven by scarcity, certainly at points, 
with the absence of hydroelectricity to the tune of several 
thousand megawatts--that there would not be really much 
management of risk on the system and to shove it on the 
customer at the very end.
    Mr. Waxman. Thank you. I would add that FERC's order 
addressing electricity prices in California may have 
exacerbated this problem by basing their proxy price formula on 
inflated spot market prices for natural gas. In fact, some have 
suggested that those orders created an incentive for generators 
to drive up spot market prices for gas in order to justify high 
electricity prices.
    Commissioner Wood, I'd like to note that the PUC's initial 
complaint against El Paso was filed in April 2000. Had FERC 
acted on it sooner, California might have been spared the 
skyrocketing natural gas prices for the winter of 2000, 2001. 
It took over a year for the Commission to set a date for 
hearing the complaint. It took 18 months for an initial 
decision.
    I know you weren't there and I also know that--in fact, I 
believe one of your first official acts after joining the 
Commission this year was to take the Commission to task for 
taking so long to act on a complaint like this. I very much 
appreciate that.
    What concrete steps have you and the Commission taken to 
ensure that petitions like the El Paso complaint don't sit on 
hold for months or even longer?
    Mr. Wood. Well, two actions, Mr. Waxman. One is an internal 
process to make sure when we have complaints that do raise 
issues of contested fact, which this was clearly one, that 
those go to a law judge to be tried in the light of day.
    Second is hiring some more law judges. We've now hired two 
just in the last week. I expect as we move into a competitive 
era, the most important thing we can provide to maintain a 
marketplace is a rapid court of justice so that allegations be 
proven; if they're not proven, that a defendant's name can be 
cleared as fast as possible so that the market can move 
forward.
    Mr. Waxman. I appreciate that. I think that's the right way 
to proceed.
    There are several other important matters pending before 
FERC including the complaint from the California PUC that the 
State's consumers are not receiving all the gas capacity that 
they contracted for. I hope the Commission is able to deal with 
these matters as expeditiously as possible. One of the lessons 
of the California experience seems to be that State regulators 
need more complete and more immediate access to information 
about gas transmissions.
    Do you believe that State regulators should have access to 
any information that FERC obtains from market participants 
about their gas transactions?
    Mr. Wood. I do. I think we've got to ensure that to the 
extent there are business confidentiality protections that are 
provided by the Freedom of Information Act, that those are 
mirrored by the State as well, so that the protections that a 
market participant has under Federal law would be the same 
protections they have would have even when we share it with our 
colleagues on the State level.
    Mr. Waxman. Thank you. Thank you, Mr. Chairman.
    Mr. Ose. Mr. Shays for 5 minutes, assuming you can find New 
England.
    Mr. Shays. Actually I'm getting drawn into this. One of the 
most courageous folks I thought that a politician ever made was 
Lowell Weickert during the energy crisis years and years ago, 
who did something contrary to what people would have thought 
Lowell Weickert would have done if they didn't know him. That 
was, he voted to deregulate energy prices in the Northeast, 
natural gas. The reason was we were just simply having a 
shortage. What ultimately happened was that prices went up a 
bit, there was more produced, there was more brought up. And we 
had the supply, we had no shortage, and ultimately we also had 
lower prices over time. It seemed to make sense.
    My looking at California on the outside just blows my mind. 
I, for the life of me, can't understand how you could 
deregulate part and not deregulate all of it. And so when I 
look at it, and people say we need to help California, while 
I'm coming from that part of the country where the chairman 
doesn't know where it is, I say why would I want to do anything 
to help California? So someone just tell me in simple terms why 
I would want to help California deal with an issue that they 
basically created?
    Ms. Lynch. I'll take that one, Mr. Shays. I agree that 
California made many mistakes in setting up a market that did 
not have effective market manipulation rules and in setting----
    Mr. Shays. Market what?
    Ms. Lynch. Manipulation rules, and rules against that, and 
also in setting up a system where essentially the market 
participant is self-regulated. What we have seen is there has 
not been self-control exercised in many markets. California has 
now taken many steps to fix some of the glaring problems in its 
own system. But in creating that deregulated system, we handed 
off important regulatory functions to the Federal Government, 
which is why the PUC needs to work with the Federal Energy 
Regulatory Commission much more than ever to make sure that our 
market functions.
    Actually, in terms of deregulation, we didn't deregulate. 
What we did was we Federalized our pricing regulation by 
creating a wholesale market, the pricing which is now 
controlled at the Federal level not at the State level. So the 
retail market is still controlled at the State level, the 
wholesale market is controlled at the Federal level. When the 
wholesale market went out of control, the State had inadequate 
tools to respond, which is why we need Federal help now both on 
the natural gas side as well as the electric side.
    But I'd like to clear up one misnomer, I think, which is 
that we set up a system that did not allow a raise in retail 
rates because we could raise retail rates. What that freeze 
was, was actually a high level. It was a floor, not a ceiling, 
in that effect. Because at the time that California Federalized 
our regulation of electric prices through creating a wholesale 
market, the price of electricity in California was about 3\1/2\ 
cents. We set the price at 6\1/2\ cents, almost double what the 
actual price was.
    So consumers were overpaying for years to allow the 
utilities to accelerate the depreciation of their capital 
assets and essentially buy those down in advance. And then when 
the market went out of control, when the price caps were blown 
out by the previous FERC, at that point prices went up in 
California to 30 or 40 cents. So, of course, the 6\1/2\ cents 
couldn't cover it.
    But no economy, no State's economy is going to be able to 
take that kind of a price shock in real time. We borrowed 
against our general fund and we'll pay that back over time. And 
because the market was so volatile and there were many mistakes 
made along the way by a variety of players, we now need Federal 
help to correct those mistakes and put in a market that works. 
Because we handed off those Federal tools--or we handed off the 
tools that used to reside with the State now to the Feds, which 
is why we have to work together and we need your help.
    Mr. Shays. Can anyone else----
    Mr. Moore. Mr. Shays, can I add something to that? There 
are a couple of lessons that are perhaps coming, unwelcomed, to 
some of the other areas. I know Commissioner Wood is well aware 
of these and will be on the lookout for them. But just let me 
mention a couple. One is the question of whether or not there 
is a surplus in capacity as markets go forward, whether they 
use that up and adequately create incentives to bring in new 
supply that is accessible. And second is the question of market 
mitigation or market monitoring.
    Mr. Shays. Just explain to me excess supply. That's a new 
concept.
    Mr. Moore. What happened in the California marketplace----
    Mr. Shays. If you have excess supply, doesn't your price 
basically lower because----
    Mr. Moore. One of the things that has protected some of the 
eastern markets, for instance in the PJM market, is the fact 
that they have a surplus in capacity. And as demand grows and 
as that surplus diminishes, as the relative surplus diminishes, 
then you can have a tightening of the market, so----
    Mr. Shays. But when you have a surplus, don't prices drop?
    Mr. Moore. Prices will be lower than they would be if there 
wasn't, or if it was a tighter market. So all I'm----
    Mr. Shays. When the prices drop, I would think demand would 
increase.
    Mr. Moore. No, I'm suggesting to you that as the market was 
created and it was moving forward, there was enough surplus 
capacity to make sure that prices stayed low.
    Mr. Shays. The chairman is hitting his gavel. With three 
members, it strikes me we could probably go beyond 5 minutes, 
but I'll wait. Thank you.
    Mr. Ose. The chairman will claim his time and yield it to 
the gentleman from Connecticut.
    Mr. Shays. I just would love someone--maybe, Mr. Wood, you 
would explain to me the concept of surplus capacity. I don't 
quite understand the concept.
    Mr. Wood. Let's take an example of--well, let's just take 
the electric market in California. Say one company has 10 
percent of all the generating plants in that market, but due to 
the hydro and all these other issues that really crunch down 
the reserve margin or the cushion--we've just always called it 
the cushion--if weather came and ran a tidal wave into a 
nuclear plant, as happened during this perfect storm, or if the 
rain doesn't show up and fill up the reservoirs in the North 
for the hydroelectricity or whatever, there has always been a 
cushion around 15 percent in the regulated world to make sure 
if something trips or something falls back or the weather is 
unusually hot, we have enough power to keep the lights on.
    The same philosophy actually carries forward into the 
competitive market, but for an additional reason, not just for 
reliability but for wiggle room for competition to actually 
work. If that 10 percent market share person was playing in a 
market that only had 5 percent excess capacity, he could say 
I'm going to keep buying 10 percent off and put it on at the 
very last minute and get $500 a megawatt hour for it instead of 
$50, because he's got market power.
    Mr. Shays. When you're using the term ``excess capacity'' 
over ``surplus capacity,'' are you using them interchangeably?
    Mr. Wood. Yes, sir, I am.
    Mr. Shays. Because the term excess capacity, for us in New 
England, basically says the plants that are the most costly and 
the most inefficient are the ones that are going to be least 
likely to be used. And then they're drawn in at the time you 
need a surge in usage. Is that how you----
    Mr. Wood. Yes, sir. Eventually those plants in New England, 
as in my home State of Texas, which have also very high reserve 
excess margins because they never get turned on at all, will 
ultimately just be mothballed or shut down. So at some point, 
your original question to Michael is correct. I mean at some 
point, that excess goes away because demand comes up or because 
that supply is retired or goes down. So it is kind of a 
constant urge on the part of all of us to make sure of that 
build-ahead margin. You can't build a plant overnight. It takes 
usually 2 to 3 years, at fastest, to get up a relatively small 
simple gas plant which is fast; but you know if you need it 
next week, that's not fast enough.
    Mr. Shays. Yes.
    Ms. Lynch. The problem is that's not how it worked in the 
California market. What happened would be that peaker plant 
that was really expensive to run would put their bid in at a 
really high price and it would be accepted because we didn't do 
least cost dispatch, meaning the cheapest or the most 
environmental sensitive goes first. It was first in goes first.
    The State kind of stepped back and said we're not going to 
run a market rule there. Whoever is in goes first. Then the 
market was set up that the person who bid the highest, 
everybody else got that too. So there was an incentive for the 
most expensive plants to bid in and everybody else enjoy a 
windfall profit. But because we handed off our pricing tools to 
FERC, California alone couldn't just go fix that. We needed to 
have FERC's consensus to go fix that.
    Mr. Shays. You could have claimed back that power, couldn't 
you? You handed it off. Why didn't you just grab it back?
    Ms. Lynch. Well, because what happened was by State law and 
by prior PUC decision, before I was on the Commission, the 
utilities sold off their power plants, by and large. So the new 
generator, the new private owner is called by FERC, not the 
State. We would have taken by eminent domain or brought back at 
market value those power plants back into the utility system to 
reclaim that power. As long as that private generator owned the 
plants, Mr. Wood was in the control of the pricing, not the 
PUC.
    Mr. Shays. Thank you, Mr. Chairman, for giving me the 
opportunity to get the complete answer. Thank you.
    Mr. Ose. Mr. Waxman for 5 minutes.
    Mr. Waxman. Thank you, Mr. Chairman. I won't take 5 
minutes. I think this panel has been very helpful. I very much 
appreciate your being here. As Mr. Shays' questions pointed out 
what we have known for a while, in California we created a 
mess. And we had to sort through it as best we could. A lot of 
it now has been in the FERC and, Mr. Wood, I'm pleased with the 
reforms you're making there. I know you're going to be looking 
at some of these issues that very much affect us. I hope you'll 
take all these issues very seriously, and I know you'll use 
your best judgment.
    Mr. Chairman, I appreciate your having this hearing so that 
we can get a lot of this information out on the record, because 
you are--I think people need to be able to put it all in some 
kind of perspective.
    I yield back the balance of my time.
    Mr. Ose. Thank you, Mr. Waxman.
    Mr. Shays for 5 minutes.
    Mr. Shays. Thank you. Thank you, Mr. Chairman. God works in 
strange and mysterious ways. I've gotten my time back.
    To now just focus on a more important side of the equation, 
Mr. Wood, what did we learn in California and what do you fear 
nationwide that you are going to be alert to, to make sure we 
don't see this repeated elsewhere? First off, is this being 
repeated elsewhere?
    Mr. Wood. No. There are things that are not going as well 
as they should elsewhere, and I really view that as our task to 
really straighten that up. In the debate that the House and the 
Senate are having as we speak on the structure and nature of 
the wholesale electric market and how competitive it will be 
and the structures that are needed to make that work, we might 
hear a debate about something called the RTOs, regional 
transmission organizations, which really are recognizing that 
electricity doesn't recognize a State's borders. It really is a 
regional commodity, perhaps not totally national but, in 
California, for example, is integrated with the western grid.
    During the peak days of the summer, the hydroelectricity 
from the West keeps the lights on in California. During the 
peak days of the winter, the excess, we hope, power from 
California makes up for the fact that the hydro was short in 
the Pacific Northwest. So it is really an integrated grid, and 
the Commission in recognizing that has really pushed for 
regional--not just Federalized but regional solutions that are 
as close to the market as they can be.
    A big part of that is providing good incentives for 
infrastructure investment, both in generation and in 
transmission lines, and also, as I think the State of 
California has shown, demand. People can respond by not 
consuming as much when the price signal is sent, as was sent 
this year in California. So that is just as viable a resource 
as a new power plant.
    Those three things, transmission, generation and demand, 
are an important factor of making a competitive market work. In 
fact, we're having a full series of workshops at the 
Commission. My colleagues and I are presiding over them. We've 
got what we call the really smart guys, the really smart gals 
in the industry coming to the table to talk through a lot of 
these issues so that we make sure, as your question points out, 
Mr. Shays, that we have learned collectively from what didn't 
work real well out in California these past couple of years, 
and make sure that in fact is not replicated, but is improved 
upon dramatically so that customers get real benefits.
    Mr. Shays. Let me ask you, as it relates to the regional 
transmission organization where FERC is proposing creating 
that, which would include New York, New Jersey, Pennsylvania 
and Maryland, that will--and noting that in Texas I think you 
basically have a totally isolated system in Texas--is 
ultimately New England going to see its prices rise because of 
this, because of the extra demand that New York and New Jersey 
and Pennsylvania and Maryland will have? How is this going to 
impact New England, in your judgment?
    Mr. Wood. We are in the process of doing our own 
independent cost-benefit analyses, as I think good common sense 
requires, but I would reference one that was done by a market 
participant in the whole Northeast that indicated that the 
savings from having an integrated grid, as opposed to three 
independent grids that work alongside each other but not 
necessarily with each other, in the Northeast would save on the 
order of $400 million per year. That would be spread, as the 
report stated, roughly----
    Mr. Shays. That because you would not, in one of those 
three, utilize the power generation that was not cost 
effective? In other words----
    Mr. Wood. Right. Rather than having the marginal plant in 
Massachusetts set New England, it might be the marginal plant 
that is the lower cost in New York or Pennsylvania set the 
clearing price for the whole region.
    Mr. Shays. Would that be a disincentive, though, for New 
England to increase its power generation if we could--or vice 
versa if we can basically say, you know, we can draw it from 
another State?
    Mr. Wood. Well, I think at some stage distance starts to 
impact the ability. I mean, that is why we couldn't draw it as 
big as the whole East. I mean, the reason Texas is separate is 
because electrically it is not on the same synchronicity with 
the entire eastern grid or with the entire western grid. It's 
just an artifact of history. But that eastern grid ideally 
would be all under one. But as a practical matter, both for 
economics and for physics, the transmission electricity over 
tremendously long distances, it really is just--is not 
pragmatic. And so we have circumscribed into natural markets--
or at least what we--appear to be natural trading markets--what 
these RTOs should be.
    Mr. Shays. Thank you very much.
    Thank you, Mr. Chairman.
    Mr. Ose. If I might offer a couple of observations for the 
benefit of my friend from New England, one of the difficulties 
we've struggled with in California is the manner in which we've 
approached deregulation. The law approving deregulation was 
written in such a way that precluded in the end the ability of 
utilities to engage in forward contracting to hedge their 
exposures, and then we got into a position where demand, for 
whatever reason, exceeded supply.
    Now the concern that I have today, as it relates to natural 
gas, is that with New England being a finger pretty much 
outside the middle of the country, how do we get natural gas 
supplies there? How do we avoid a repeat of what occurred in 
California at the other end of the pike? And that is really 
what the purpose of this hearing is about.
    Mr. Wood, in terms of interstate pipelines, whether it be 
California at the end or Maine at the end, what are the 
barriers to approving the installation of those pipelines?
    Mr. Wood. They're primarily at this stage two, and they are 
not barriers. They're just the way it is. One is landowner 
concerns, which oftentimes tie back to safety concerns about, 
you know, volatile product, and environmental concerns, and the 
Congress has passed a number of environmental laws over the 
years that must be observed by any company that is wanting to 
construct a natural gas pipeline or any other public facility. 
So those are the barriers primarily.
    At this stage, the Commission's certificate policy, in the 
10 years since I was there as a staffer and now, has 
substantially moved to a much more market-oriented, where if 
you have sufficient contract and people who are willing to pay 
for the pipeline or to the expansion of a pipeline, for 
example, then that really establishes the need. The market 
establishes the need. In prior days, that used to be a 
complicated regulatory process, where you'd have economists 
back and forth and State commissions back and forth, and it 
would be years before you'd get a pipeline built, you know.
    In most instances, even relatively large pipelines, I think 
our average is now below 240 days to do a full pipeline 
project. There are a few outliers that are very controversial, 
but, by and large, those are not the rule. They're the 
exception. So the barriers are substantially lower than they've 
ever been.
    Mr. Ose. One of the things that gets missed here is that 
the construction of pipeline capacity is not the only solution 
to a supply issue. In other words, you can build storage to 
balance your peaks and valleys.
    The same question they just asked regarding interstate 
pipelines, does FERC have jurisdiction over storage facilities 
being built?
    Mr. Wood. We do, although there are some that are outside 
our jurisdiction. If they're owned, for example, by a local gas 
distributor, such as SoCalGas, and they're used within the 
California region, those would not be under our jurisdiction 
but under President Lynch's jurisdiction.
    Mr. Ose. I presume that would be the same then for 
something in New England?
    Mr. Wood. Same in New England. By and large, we do have a 
number of interstate storage facilities that the Commission 
does certificate, and, again, those are processed relatively 
routinely and usually in a very--less than 1-year timeframe.
    Mr. Ose. But that is gas dedicated to the interstate 
market, not to an intrastate market?
    Mr. Wood. Right, and basically it's one of those 
jurisdictional fine lines that we have been pretty deferential 
to States, that in the State PUC said, you know, we just have 
one in Ohio, for example, of a couple of meetings back where it 
was really probably a close call, and if there was mingling of 
gas in the interstate and intrastate markets, but because it 
was under the State jurisdiction and State regulatory regime, 
then the Commission said at that point we will disclaim 
jurisdiction over that and let that be regulated by the State.
    Mr. Ose. Mr. Moore, you're the economist, if I recall. On 
the storage issue--I see my time is about to evaporate, but I 
want to get to this. The existence of a storage facility, 
whether it be dedicated to interstate or intrastate gas 
storage, allows a purveyor of the end product to contract for a 
steady flow at a relatively low price, for instance, because of 
the certainty involved. And then on the far side of the 
transaction, when demand comes up, they have a much larger pipe 
coming out of the storage facility than, say, going in, and 
they can surge their supply.
    Now, what is the impact on pricing for having that ability 
in the general sense?
    Mr. Moore. Perhaps the better way to put that is what is 
the impact of not utilizing it? Right now, the State is set up 
so that we achieve a balance between storage and the pipeline 
system, part of which can be packed so as to get a short-term 
response from more gas in the pipe that can be released in a 
shorter period of time. So, when the purveyors balance the use 
of storage as well as the pipeline, then the system works 
really up to capacity. And with the mist that prevails, then we 
can have some shortages and, as a consequence, have some price 
increases that were unexpected. So they have to be used in 
tandem. They have to be used in balance to make sure that we 
achieve the lowest possible price regime.
    Mr. Ose. So it's not all pipeline, neither is it all 
storage? I mean, that is not the answer?
    Mr. Moore. No. Congressman, that is not the answer.
    Mr. Ose. All right. Mr. Shays for 5 minutes.
    Mr. Shays. Thank you.
    Mr. Ose. Mr. Wood, in terms of the issue that Mr. Moore 
just highlighted in California that it's not all storage and 
it's not all pipeline, does that also exist in other parts of 
the country, that particular dynamic?
    Mr. Wood. Absolutely. My first client as a lawyer was a 
bunch of distributors in Wisconsin, and they depended very 
heavily on gas storage fields in Michigan, which they filled up 
in what we call the shoulder months, March, April, August, 
September, October. They injected gas into those Michigan 
storage fields to take them out in December, January, February 
when they really were burning a whole lot of gas. So they took 
full out from the pipeline that went south, and I believe one 
went to Canada, they took full out in the winter and took gas 
from storage. Storage becomes in effect a third pipeline into 
that region, just like the case in California.
    Mr. Ose. Now, you have jurisdiction over interstate storage 
and interstate pipelines?
    Mr. Wood. Yes, sir.
    Mr. Ose. Why is it that if my memory serves, there is only 
one interstate pipeline that comes into California.
    Mr. Wood. Kern, Mojave.
    Mr. Ose. What is the issue in terms of an interstate line 
coming into California to serve a dedicated need?
    Mr. Wood. Well, I guess you don't really--as I think the 
issue that you walked through with Mr. Lorenz a moment ago, you 
don't really need to do two kinds of books, basically. You just 
buy the capacity on the one line, and it's really a seamless 
transaction.
    I think that's certainly what the shippers that have taken 
service from Kern want, is that ability to have the same level 
of firmness of capacity from their burner tip all the way back 
to some point, perhaps all the way back to the wellhead, and I 
think the offering of that service has made at least those 
pipelines more attractive to certain types of customers than 
the need to perhaps have a less firm product on SoCalGas and 
some product combined with that from either El Paso or 
Transwestern.
    Mr. Ose. I want to go back to the storage. This dynamic 
between storage and transmission intrigues me. You have 
jurisdiction over utility storage or just private company 
storage?
    Mr. Wood. I think the best way to think about it is, if 
it's retail, it's theirs. If it's wholesale, which means you're 
doing storage on behalf and for--to sell it to somebody else, 
sales for resale, I guess is the best way. So if I run the 
storage cavern and it's attached to an interstate gas pipeline 
and I'm selling that gas to a marketer or to a local gas 
utility for their ultimate resale to an end-use customer, then 
it would be FERC. There are exceptions to that, but, by and 
large, retail, wholesale are probably the best way to split the 
universe there.
    Mr. Ose. So an end user who's drawing out of storage would 
go through the Public Utilities Commission of a State?
    Mr. Wood. Yes, sir.
    Mr. Lorenz. All storage in the State of California is 
regulated by the CPUC at this time.
    Mr. Ose. OK. So if I'm going back to your point earlier 
about locating generating facilities in a State, whether it be 
California or Nevada or Colorado or New Mexico or wherever, I'm 
trying to understand whether or not the CPUC allows--and this 
is for Mrs. Lynch--a direct connection between a storage 
facility for a peaker plant or a connection between a peaker 
plant and a storage facility for surge of gas? In other words, 
can that be a direct connection, or does the peaker plant have 
to go through a utility to get the gas?
    Ms. Lynch. Many of the utility storage fields are reserved 
for core customers to a certain percent, which would be the 
nonelectric generators and nonlarger customers, and then also 
some of their capacity is reserved for the larger customers. So 
I would actually--in terms of how SoCalGas specifically 
allocates that, I'd defer to Mr. Lorenz.
    But we also have a couple of additional private facilities 
that the PUC is either working on or has in fact approved. So, 
for instance, Lodi Gas Storage, which we approved in 2000, I 
believe will be up and running into this year or at least 
during this winter of 2002--2001, 2002.
    Then there is another petition for an additional private 
gas storage facility in front of us that was filed this summer 
by Wild Goose Storage, who is one of the panelists on the next 
panel.
    Mr. Ose. They're on the next panel, right.
    Now, the gas that goes into the storage facilities, do the 
contracts for the acquisition of that gas by the storage 
facility come before the PUC? In other words, I mean, they're 
going to take a steady flow over a course of time to fill their 
facility.
    Ms. Lynch. Right.
    Mr. Ose. Does the contract for that steady flow come before 
the PUC?
    Ms. Lynch. It is the approval to build the storage facility 
itself.
    Mr. Ose. But not the flowage?
    Ms. Lynch. No, I don't know at any particular point in time 
what SoCalGas's contracts look like. We know the percentage 
generally between what they're storing for their core customers 
and what the noncore customer storage is, but I can't tell you 
today who all their noncore customers are who pull from 
SoCalGas's storage.
    Mr. Ose. It just doesn't make any difference to you in 
terms of who's supplying that gas? I mean, from a regulatory 
standpoint, you don't care how the gas gets in----
    Ms. Lynch. Well, from a regulatory standpoint, we want to 
make sure that there's adequate storage and that there's 
adequate storage for the core customers at a reasonable price. 
Because our statutory job is to ensure just and reasonable 
prices at the retail level. So we need to make sure that 
there's enough capacity to keep that price reasonable.
    Mr. Ose. So I guess I'm back to my original question. Do 
you look at those actual transactions for the acquisition of 
the gas that goes into storage, or do you not?
    Ms. Lynch. We don't approve those actual transactions, no. 
We may know some of them. So, from time to time, we know who's 
transacting with the various storage fields, but it's not who 
injects gas into SoCal's storage field. It's not a regulatory 
approval by the PUC.
    Mr. Ose. New England disappeared.
    In terms of drawing the gas out of storage for use by a 
third party--let's say in Mr. Lorenz's instance, a generator 
and maybe this question is for Mr. Wood--is that a transaction 
that is subject to FERC's jurisdiction or the PUC's 
jurisdiction?
    Mr. Wood. Again, you're referring to the example we've just 
been talking about where you've got some part of storage that's 
dedicated to large customer use? That would not--it's 
unbundled. It's an unbundled rate that Loretta and them 
approved. That would not be under FERC.
    Mr. Ose. But that would be under the PUC?
    Ms. Lynch. Or it would be a private contract with SoCalGas. 
But generally we set the utility's rates such that I think that 
really establishes the playing field for the contracts----
    Mr. Ose. So they just domino backward to the pricing on 
their transaction at the pump head, so to speak?
    Ms. Lynch. Well, for instance, we set a peaking rate and we 
set a firm transition--or firm capacity rate, things like that. 
So I guess in context then you add up all those various rates 
depending on the kind of service that contractor is going to be 
getting, and it comes down to the rate.
    Mr. Ose. Mr. Lorenz, I mean----
    Mr. Lorenz. Let me----
    Mr. Ose [continuing]. Illuminate this for me.
    Mr. Lorenz [continuing]. Try and add a little bit more.
    The SoCalGas system currently has 105 billion cubic feet of 
storage capacity; 70 billion of that is dedicated to the core; 
30 billion is unbundled and made available on a contract basis 
to noncore customers, and then 5 billion is used for balancing 
services. That 30 billion that is unbundled and made available 
to noncore customers is done on a contract basis. The maximum 
rates are set by the CPUC for all three classes of storage 
services.
    Mr. Ose. On the sales side?
    Mr. Lorenz. On the sales side. For the inventory space, for 
the injection capacity and for withdrawal capacity, the CPUC 
sets the maximum rates for those, and then we are at risk for 
the recovery of that revenue that is being unbundled, and we 
operate it like a business.
    Mr. Ose. Even now that you have a cap that you're going to 
get, you can sell it for this much revenue, so you've got to 
buy it for something less, because you've got costs between 
here and there?
    Mr. Lorenz. That's correct.
    Mr. Ose. OK.
    Mr. Lorenz. Now, we don't buy the gas that goes into that 
unbundled storage. That is, those transactions are done by the 
parties that hold that capacity. So we sell the capacity to 
them at rates that are regulated by the PUC and then they 
utilize it as they see fit. They determine when they want to 
buy gas and put it in, when they want to take it out. They use 
it to balance their load between seasons and also on a daily 
basis to balance their load----
    Mr. Ose. In effect, you're just holding the commodity for 
somebody else?
    Mr. Lorenz. That's correct. Our field is the bank.
    Mr. Ose. Now, the storage facility itself, on an intrastate 
basis, is subject to CPUC review and approval?
    Ms. Lynch. On an intrastate basis, yes.
    Mr. Ose. There can be in your storage facility both 
intrastate gas and interstate gas, though?
    Mr. Lorenz. The gas would all have come across an 
interstate system and then across the intrastate system in 
order to go into storage----
    Mr. Ose. At which point it is all intrastate gas----
    Mr. Lorenz. That's correct.
    Mr. Ose [continuing]. Subject to the PUC jurisdiction?
    Mr. Lorenz. That's correct.
    Ms. Lynch. Well, theoretically, there is--15 percent of the 
gas that we use is produced inside California. So, 
theoretically, any of the storage fields could hold California-
produced gas as well.
    Mr. Ose. All right. Here's the essential issue that we all 
struggle with up here, and that is what can Congress do, 
regardless of region, based on what we've experienced in 
California, to prevent these capacity problems from replaying 
themselves elsewhere? The collective wisdom here is 
significant. Give us some guidance for the record. Mr. Wood.
    Mr. Wood. I think the steps that we have collectively taken 
over the last 12 months, unfortunately in a reactive mode and 
not a proactive mode, are probably the right ones--making sure 
that market rules are clear, making sure that investment 
signals are sent and that, in fact, investment is done.
    Then, finally, and I don't know that we do enough of this 
in our job, listen to what the customers want, and if customers 
want to have firm rights, they want to have interruptible 
rights or they want to have some version of the two, they want 
to have access to Canadian or Alaskan or Mexican or San Juan or 
Texas or midcontinent gas, then let's go there, as long as 
they're willing to pay the fair rate for it. And I think--
excuse me--there are plenty that do. In fact, customers are 
willing to do that, because the gas cost is relatively 
competitive.
    That listening to the customers probably is the wisest step 
of all. Plenty of them have spoken out lately.
    One of my first visitors was a set of dairies and farmers 
from California and some of the issues they had with respect to 
their natural gas costs. I mean, they weren't there as mad 
electricity consumers. They were there as mad gas consumers, 
because it affected everybody.
    So infrastructure, tariffing and customer rules and also, 
you know, as I think are pointed out, the policing of the 
market to make sure that everybody is playing by the rules. So 
those three things. I think we've got the authority to do that 
at the Federal level. I think the State does. Loretta and 
Michael can speak clear to that.
    But I think, as far as further legislation, I don't suggest 
any, but if the Congress would like to go in that direction we 
can certainly provide any technical assistance you like.
    Mr. Ose. I want to ask specific questions about this.
    In the financial markets, people hedge their exposures. 
Some areas of this country, utilities are able to hedge, and in 
some they are not. Is that a tool that needs to be provided to 
utilities, or can that exposure be addressed in some other 
manner?
    Mr. Wood. Well, the other manner is politically not 
feasible, so I think the answer is it's possible, but it's not 
very popular.
    So I think allowing utilities to have the kind of tools 
that any other customer should have to be able to--I could 
manage my risk by buying insurance. In effect, buying a long-
term contract for power, for gas, is something that--when I was 
a former State regulator, we didn't really--in an age when 
there was a lot of gas, you didn't really reward a utility for 
getting a long-term contract.
    In fact, there were a lot of people that showed up at the 
Texas Commission to try to second-guess utility X for having a 
long-term contract. Having a $2.50 contract in a 97 cent market 
usually meant that the utility was going to take something in 
the shorts. So that was something utilities just said, ``Forget 
it. We get no reward for taking an advantageous position in the 
long term. So we don't do it at all. We'll live on the spot 
market.''
    Well, that's great when there's a lot of gas, there's a lot 
of electricity. The spot market is a great place to be. But 
when conditions get tight, for whatever reason, lack of an 
investment or bad weather or something like hydroelectricity 
shortfall, then you start to have--you start to have those 
thoughts that a $2.50 gas contract sure would have been nice to 
have.
    That's the most crude form of hedging. The financial tools 
that are available today are much more sophisticated and quite 
a bit more varied than a long-term contract. But that is an 
example of the type of things that State regulators--and I 
think President Lynch can speak for what they do.
    Mr. Ose. You're saying having the flexibility to do it, but 
not having the mandate to do it or not do it is the piece that 
needs to be included?
    Mr. Wood. Yes, because the mandate really--you--a regulator 
is never as good as a businessperson at really balancing the 
risk in the portfolio. And I think allowing utilities to have 
tools, allowing them to keep some reward for when they make 
good decisions and penalize them when they make bad decisions, 
just like a market would do, is kind of what we do. And so we'd 
like to replicate the market as much as we can, and providing 
both carrot and sticks is a good way to do that.
    Mr. Ose. All right. Ms. Lynch, same question, 
recommendations to Congress on how we address these things 
going forward, including the last question about the tools 
given the utilities.
    Ms. Lynch. Certainly. One is just exactly what you're doing 
now, which is adhering to make sure that the State and the Feds 
are working together. And I would tell you that, under Chairman 
Wood's leadership, we're working together much better than we 
have worked together in the past several years, because I think 
that Chairman Wood, as a former State regulator, understands 
the State's concerns and is appropriately listening to us, 
which we really appreciate, and also moving forward our 
complaint at the FERC rather than, as the prior FERC had done, 
was really just sitting on them or we'd get in the queue.
    But, also, I would just urge you to make sure that you work 
with FERC to make sure that they have adequate remedies 
available in the Natural Gas Act to provide refunds where 
appropriate where market power has been exercised for past 
behavior.
    Now, the PUC has certainly taken the position that they 
have that authority. Other parties have questioned whether the 
FERC has that authority. But Congress can make certain that the 
FERC has the full panoply of tools available when they find 
market power to make sure that Californians essentially don't 
find a violation without a remedy. And we want to make sure 
that the Natural Gas Act provides all the remedies that the 
FERC believes it needs to make sure that our markets are 
competitive going forward and also so that they can deter 
practices that have happened in the past.
    Then, finally, as to utility hedging, I'm a firm believer 
in a power procurement portfolio. You can't have all long-term 
contracts. You can't have all spot prices. California has kind 
of swung by a pendulum back and forth now, but what certainly 
the long-term contracting of recent times has shown us is that 
you need some kind of review, as the chairman said, so that you 
can reward folks who are making good decisions and penalize 
them for making bad. What you don't want to do is per se find 
reasonable any price made in a long-term contract because then 
you could have the El Paso situation where they contract with 
their own affiliate for a higher price than otherwise would be 
reflected in the market. So I think that California PUC has 
that authority to move forward with a power procurement 
portfolio.
    We were working with the legislature on a bipartisan basis, 
the State legislature, to come up with standards for power 
procurement. That bill did not pass, but, nonetheless, the PUC 
is moving forward. And on our next agenda, on October 25th, 
we're sending out a consensus rulemaking on trying to figure 
out some boundaries for long-term contracts as well as medium-
term contracts, as well as spot prices, so that the utilities 
can have some more certainty along with being rewarded and 
penalized for really blatantly good or bad decisions moving 
forward so that they can once again do what they were doing 
before, which is provide appropriate power procurement 
portfolios for their whole load; and a mix of power structures 
and hedging tools would be part of that.
    Mr. Ose. Within the portfolio, do you have any sense of 
what percentage should be dedicated or provided by long-term 
contracts versus spot acquisition? Is that one of the issues 
you----
    Ms. Lynch. That is one of the issues, and I don't think 
that you can--and I don't think that the PUC should set 
absolute mandates on those points because the market is going 
to change and the utility needs to be able to exercise its 
business discretion as the markets change, because you don't 
want to be caught in what happened in 2000, which is the 
markets changed rapidly. We were locked into a legislative 
structure that did not allow rapid response to that change, and 
the utilities kind of got caught holding the bag there. So you 
want to make sure it's flexible enough but put boundaries on 
their actions so that the consumers aren't caught holding the 
bag.
    Mr. Ose. So, in effect, you're going to define a safe 
harbor for a utility that wants to enter into a forward 
contract?
    Ms. Lynch. Potentially. We're just starting the rulemaking, 
hopefully on the 25th, and then we'd have parties come in and 
make proposals. What we would do would be essentially to ask 
the utilities to come in and make proposals about what their 
power procurement portfolios would be and also ask them to make 
a proposal very specifically that would align with a bipartisan 
bill sponsored by Assemblyman Wright that died in the last days 
of session but which was a consensus proposal between the 
utilities, the sellers, the PUC and the consumers. So we're 
hoping to move along the lines of that bill, although it may 
not look exactly like that once it goes through our public 
process.
    Mr. Ose. So creating those standards is probably one of the 
objectives--I mean, you're going to start the process for 
creating those standards----
    Ms. Lynch. Right.
    Mr. Ose [continuing]. Here in late October? Any idea what 
kind of timeframe it will take to get to the end?
    Ms. Lynch. Well, frankly, we want to do that on an 
expedited basis, which would mean just a few months rather than 
a year, which would be the normal process for the PUC, because 
we want to get the utilities back into the power procurement 
business and, frankly, get the State out of that power 
procurement business to the extent possible. That is 
complicated by the PG&E bankruptcy, but we believe we can move 
forward, nonetheless.
    Mr. Ose. OK. Mr. Moore, same question.
    Mr. Moore. Mr. Chairman, I'll make it very, very short.
    I think that Chairman Wood has proved that he's got the 
tools that he needs and that it takes a will and some foresight 
to be able to exercise them to make the market move and to 
let's say corner the market into the proper behavior. I think 
that it's probably not the need--there's not a time right now 
to institute new rules from the congressional level. I think 
that they got what they need at FERC, and frankly I think if 
you look at the circumstances in California it has showed that 
the regulators ought to be left a little bit more alone from 
the legislature to be able to do their job and to be able to 
perform their functions.
    I, for one, am certainly not speaking for Commissioner 
Lynch, but it seems to me I would have felt happier with the 
PUC being able to do their job with a little less legislative 
interference. I think the outcome might have been a little 
quicker and perhaps a little cleaner. My guess is that the role 
of the Congress is exactly what we're doing today, which is to 
provide the oversight and provide the forum in which these 
kinds of debates can go forth. Because when you do invite the 
actors here in these Chambers, you tend to get a more open 
airing of the facts, a more open airing of the circumstances, 
and, frankly, I think you give the regulators more room and 
more incentive to do their job. So what you provide is really 
the muscle behind the regulators being able to do an effective 
and impartial job over time.
    The last piece of the puzzle is information, and it's the 
area where I think we and the States can cooperate and give a 
tremendous additional tool to the FERC, because they're not 
staffed in volume to be able to look at all the different 
markets in all the different States. So when we can provide the 
impartial and up-to-date and timely information on the trends 
and on the market niche activities, I think that the market 
surveillance, the oversight in terms of market manipulation or 
market power will be just that much more powerful at the FERC 
with our cooperation; and I think that is the right forum.
    Mr. Ose. One of the things that your written testimony that 
I read, I found very interesting, was that along these 
interstate lines demand fluctuates depending on seasonality and 
temperature and what have you. But over the long term, it's an 
increasing level of demand, that it just--the angle is up. Now, 
if the capacity of the line is X and demand, for instance, at 
the start is like 0.5 X, but then over 10 years grows to 1.25 
X, how do we integrate that growth in demand along the line so 
that FERC approves the added capacity so that the person at the 
end of the line, specifically California, doesn't end up short 
of gas in an untimely manner? Is that the information kind of 
issue that you're talking at?
    Mr. Moore. Mr. Chairman, that is part of the information.
    Certainly, I think we were surprised to see some of the 
upstream demand occurring at the rates that it did or the rates 
that it is increasing. The two new plants in Arizona are a good 
example. We cited those in the testimony. And I think that we 
need to be cognizant of that, being at the end of the line, and 
so does the FERC.
    I guess the best example of how to get there, for me as a 
commissioner, is to refer to Commissioner Wood's suggestions 
for RTOs, the regional transmission organizations, and to say 
that to begin to imagine our participation in a regional 
context is probably more important than anything, because--than 
anything else that we can do in the information world, because 
we are not alone. We operate under the influence of and we 
influence behavior in our neighboring States.
    And so, using the RTO model just as an icon for a second, 
I'll tell you that if we don't start thinking more broadly 
about some of the upstream demands that will impact us, we will 
find ourselves short. We in the information generating business 
can supply a lot of that to FERC ahead of time and, frankly, I 
think influence the nature of their decisions and the 
mitigation measures that they might impose on any of the 
approvals and certification that they give at their end.
    Mr. Ose. Thank you.
    Mr. Lorenz, same question.
    Mr. Lorenz. I'll also try and be brief.
    I believe the storage market in California is operating 
effectively at this stage. There were some important lessons 
learned last year. Parties that contracted for storage elected 
not to fill that storage. Last year, they relied on the forward 
price curve that said prices were going to continue to decline, 
and so where's the incentive to store now when the forward 
price curve says prices are going to decline? Well, that curve 
turned out to be wrong, and they paid the price. Associated 
with--that storage now is 50 percent higher at this time on our 
system than what it was a year ago. So I think the market has 
made those adjustments, has learned those lessons and is 
operating effectively.
    I think utilities ought to have all the tools that are 
available in the marketplace to manage their risks--hedging, 
contracting on a forward basis, long-term contracting. All of 
those opportunities should be available, and a portfolio is an 
important element to have----
    Mr. Ose. So you would applaud the PUC taking this up and 
trying to define those, as Ms. Lynch indicated?
    Mr. Lorenz. Absolutely.
    Mr. Ose. You're supportive of that?
    Mr. Lorenz. Absolutely. We have a very effective mechanism 
on the gas side already in place that provides exactly that 
kind of incentive mechanism. That cost of gas is compared 
against a market price. The cost that the utility purchases the 
gas at is compared against a market price to determine how 
effective we are in buying. If we're doing real well, we get to 
share in those benefits along with the ratepayers; and if we're 
not so good, we get penalized.
    Thus we have aligned those ratepayer and shareholder 
interests through an incentive mechanism that works very 
effectively on the gas side.
    Mr. Ose. So as far as what Congress might do or consider 
doing, you think the market's responding a lot more efficiently 
than the Congress ever will?
    Mr. Lorenz. I believe that the market is responding 
appropriately at this stage.
    Mr. Ose. All right. We have additional questions, but, in 
the interest of time, I told Commissioner Wood we'd be out of 
here at 1:40 with this panel, so I'm 7 minutes late, but we 
have some additional questions. To the extent that we didn't 
get to them, we'd like to send them to you. We would like to 
have your written responses.
    I do appreciate the four of you taking the time to come and 
visit with us today. I know that you are very busy, but your 
input is appreciated. So thank you all.
    Mr. Wood. Thank you.
    Ms. Lynch. Thank you.
    Mr. Ose. We're going to take a 5-minute recess here, and 
then we're going to have the second panel.
    [Recess.]
    Mr. Ose. OK. We're going to go ahead and convene the second 
panel. I see Mr. Kalt is not--Mr. Kalt? Mr. Kalt? We have sworn 
everybody in. We have lost a witness. Maybe he went to New 
England.
    I want to thank you for your patience, first of all, in 
getting to this point.
    Our second panel is comprised of four individuals. We have 
Paul Carpenter. He's principal in the Brattle Group. We have 
Professor Joseph Kalt from the JFK School of Government at 
Harvard University; Paul Amirault, vice president, marketing, 
Wild Goose Storage, Inc., best storage facility in the country. 
Then we have Gay Friedmann, the senior vice president, 
legislative affairs, for the Interstate Natural Gas 
Association.
    You've heard my explanation earlier. Green light, yellow 
light, red light; 5 minutes for your opening comments. We've 
got each of your statements here, and we have reviewed them.
    I want to welcome you. Professor, thank you.
    Mr. Carpenter, for 5 minutes to summarize.

  STATEMENTS OF PAUL R. CARPENTER, PRINCIPAL, BRATTLE GROUP; 
 PROFESSOR JOSEPH KALT, JOHN F. KENNEDY SCHOOL OF GOVERNMENT, 
 HARVARD UNIVERSITY; PAUL AMIRAULT, VICE PRESIDENT, MARKETING, 
   WILD GOOSE STORAGE, INC.; AND GAY FRIEDMANN, SENIOR VICE 
    PRESIDENT, LEGISLATIVE AFFAIRS, INTERSTATE NATURAL GAS 
                     ASSOCIATION OF AMERICA

    Mr. Carpenter. Thank you, Chairman Ose, for the invitation 
to be here today. I'm very honored to do so.
    The success of future regulatory oversight of U.S. natural 
gas and electricity markets will depend on the ability of our 
regulators to monitor the performance of these markets and, 
thus, the conduct of participants that may possess market 
power, which we define as the power to profitably raise prices 
by restricting output. As Chairman Wood's recent draft 
strategic plan for the FERC recognizes, sufficient oversight of 
market conduct is necessary if we're to rely increasingly on 
competition to determine prices and output in these industries.
    California's natural gas and electricity market experience 
in 2000 and 2001 provides perhaps the first significant test of 
that regulatory challenge. Earlier this year, my colleagues and 
I conducted a comprehensive study for Southern California 
Edison Co. on the question of whether El Paso Merchant Energy, 
the largest holder of interstate pipeline capacity rights to 
California at that time, possessed and exercised market power 
so as to drive up the price of natural gas and, thus, 
electricity to California during the period March 2000 through 
March 2001. This study was submitted to the Federal Energy 
Regulatory Commission in the complaint proceeding brought by 
the CPUC. I testified in that proceeding this summer on the 
results of our study.
    Last week, the FERC's administrative law judge issued his 
initial decision in the CPUC v. El Paso matter. This initial 
decision finds that El Paso and El Paso Merchant Energy 
violated the FERC's affiliate rules when El Paso Natural Gas 
awarded 1.2 billion cubic feet per day of pipeline capacity to 
California to its unregulated marketing affiliate, El Paso 
Merchant.
    It also finds that El Paso Natural Gas and Merchant Energy, 
as a result of the contract, possessed market power in the 
market for delivered natural gas supplies to Southern 
California and that El Paso Merchant garnered, ``tremendous 
profits,'' during the term of the contract. But the ALJ was 
unable to make a definitive finding based on the record in the 
case that El Paso Natural Gas or Merchant Energy actually used 
their market power to raise prices.
    In my view, the judge's acknowledged inability to find 
clarification in the record on the market conduct evidence 
compels the full commission to look at the record evidence 
carefully when it reviews its initial decision. This is 
important, because it is clear to me that much of the future 
regulatory work of the FERC will involve similar evaluations of 
the behavior of market participants in partially deregulated 
markets, such as in California. If the regulator cannot come to 
grips with this kind of behavioral evidence based on actual 
transactions in the market, then it will be very difficult to 
perform the oversight function required to permit competition 
to substitute for regulation.
    While gas markets are admittedly complex, electric power 
markets are even more so. If evidence of market power abuse 
cannot be discerned from the record in the CPUC-El Paso matter, 
then I have serious doubts as to whether it could ever be found 
in a matter involving electric power generation. For example, 
to give you a bit of a flavor for the kind of evidence 
introduced at the hearing and the kind of evaluation required, 
I included in my written statement today a few of the exhibits 
which are part of the overall picture in that record.
    The evidence goes to the key question of whether El Paso 
withheld capacity from the market during the summer and fall of 
2000 when prices began to rise significantly and when storage 
injections should have been occurring in anticipation of the 
coming winter. Did El Paso Merchant Energy fully utilize its 
capacity during the storage fill period of March 2000 through 
October 2000, as compared to the other large shippers on El 
Paso? The answer is clearly no, as evidenced by figure 5 in my 
presentation.
    During this period, Merchant Energy's average utilization 
was 44 percent, although the three next largest shippers--
Burlington, Williams and SoCalGas--achieved 87, 84 and 86 
percent utilization rates respectively. Did El Paso Merchant 
Energy even attempt to fully utilize this capacity during this 
period as compared with other shippers? That answer is clearly 
no and is depicted in figures 6 and 7 of my submission, which 
compare nominations and flows between Merchant Energy and all 
other shippers on a monthly and daily basis respectively.
    In his initial decision, Judge Wagner states that during 
this period, when El Paso Merchant did not nominate 100 percent 
of its capacity, the relevant question is whether other 
shippers had sufficient capacity to make up the slack. The 
evidence slows that if El Paso Merchant--and I'm quoting the 
judge--had attempted to exercise market power by restricting 
its nominations and flows of gas to California during the 
summer of 2000 and thereafter, other firm shippers who were 
experiencing cuts in their own nominations could have flowed 
and would have every incentive to flow more gas.
    In my view, that conclusion flies in the face of the 
evidence of actual conduct established at the hearing. The 
other shippers did nominate nearly all of their capacity during 
this period and achieved very high utilizations. Even if the 
evidence supported the conclusion, one must ask whether 
evidence of actual withholding conduct by a firm with market 
power can be dismissed simply because other smaller shippers 
could have flowed more gas but chose not to.
    In conclusion, no matter what the eventual outcome, the 
CPUC v. El Paso matter will be a bellweather case, illustrating 
the kinds of economic evaluation of market conduct that will be 
required of future regulators. We will not be successful in 
promoting competition as a substitute for regulation if the 
regulatory oversight function cannot distinguish 
anticompetitive conduct from competitive conduct.
    Thank you very much.
    Mr. Ose. Thank you, Mr. Carpenter.
    [The prepared statement of Mr. Carpenter follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.055
    
    [GRAPHIC] [TIFF OMITTED] 82547.056
    
    [GRAPHIC] [TIFF OMITTED] 82547.057
    
    [GRAPHIC] [TIFF OMITTED] 82547.058
    
    [GRAPHIC] [TIFF OMITTED] 82547.059
    
    [GRAPHIC] [TIFF OMITTED] 82547.060
    
    [GRAPHIC] [TIFF OMITTED] 82547.061
    
    [GRAPHIC] [TIFF OMITTED] 82547.062
    
    [GRAPHIC] [TIFF OMITTED] 82547.063
    
    [GRAPHIC] [TIFF OMITTED] 82547.064
    
    [GRAPHIC] [TIFF OMITTED] 82547.065
    
    [GRAPHIC] [TIFF OMITTED] 82547.066
    
    Mr. Ose. Professor Kalt for 5 minutes.
    Mr. Kalt. Thank you, Chairman Ose.
    I appreciate the opportunity to appear here today. It's no 
secret that the question of what caused California natural gas 
prices to rise beginning in mid-2000 is a contentious one. I 
played a role in that debate by testifying on behalf of El Paso 
Merchant Energy in the recent FERC hearings. If nothing else, 
the intensity of that proceeding has given me the opportunity 
to examine tests and be tested on the data and evidence 
relating to recent natural gas prices, supplies and 
infrastructure in California. Based on this, the only other 
explanation that makes sense to me in the debate that the FERC 
has undertaken and heard is the supply/demand explanation.
    I think it is evident that by the second half of 2000 an 
unprecedented and unfortunate confluence of events created a 
situation in which absolutely extraordinary levels of natural 
gas demand combined with the gas supply delivery system that 
was pushed to its practical limits. With demand booming and 
pipeline infrastructure effectively maxed out, the inevitable 
result was sharply higher prices.
    Supply was restricted by infrastructure. I do not think 
that the evidence indicates that there was artificial 
withholding of supply through an exercise in market power. Let 
me briefly review what happened in California.
    Going into the summer of 2000, storage inventories were 
essentially on a par with historic levels. The delivery system 
serving California consumers generally had additional capacity 
available to enable a response to a typical season's upswing in 
demand, but in the second half of 2000, things turned out to be 
anything but normal. On top of a growing California economy, 
the summer of 2000 turned out to be one of the hottest on 
record. At the same time, normal inputs into California of 
hydroelectric power from the Pacific Northwest were severely 
hampered by drought. June 2000 hydroelectric output in the 
Northwest, for example, was 23 percent lower than the June 
average for the previous 5 years.
    The market's supply and demand forces played out in the 
context of a set of crucial State policies. Until very 
recently, the California Public Utilities Commission has found 
it expedient to support a nonexpansionist policy with respect 
to the natural gas transportation infrastructure serving 
California. Specifically, under policies designed to insulate 
so-called core residential and small commercial customers from 
upward pressure on gas prices, policymakers in California have 
been under pressure to implement a policy that limits the 
options of larger noncore industrial and other customers, 
keeping them tied to the transportation facilities of the 
State's incumbent regulated utilities.
    To top things off, the passage of summer into fall and 
winter gave California no breaks. The winter of 2000-2001 
developed as unusually cold, again spurring demand for electric 
power and the gas needed to produce such power.
    It's hard to overstate just how dramatic the increase in 
demand for natural gas was in California in the second half of 
2000. Energy economists have a rough rule of thumb. The growth 
rate in energy demand tends to be about the same or a little 
bit less than the growth rate of the economy in general. So if 
the economy is growing 3 or 4 percent, we expect energy demand 
to grow maybe 2 to 3 percent.
    In California, in the second half of 2000, statewide demand 
for natural gas was almost 20 percent higher than any previous 
year. In the case of the Southern California Gas system, for 
example, compared to the same months in 1994 through 1997, June 
2000 demand for natural gas was 42 percent higher than the 
average of prior Junes. July 2000 demand was 39 percent higher. 
August 2000 demand was 34 percent higher. September 2000 demand 
was 28 percent higher. October 2000 demand was 30 percent 
higher.
    These extreme increases in demand experienced in California 
in the second half of 2000 put the State in quite a bind. 
Beginning in the summer, the shippers who were trying to sell 
gas into California began to find their nominations to move 
more gas being cut due to infrastructure capacity limitations. 
They could not move all of the gas they wanted to California. 
The result was that instead of building storage inventories, as 
would normally happen in the summer, California utilities found 
themselves drawing down their storage of gas just to keep up 
with demand.
    Under these conditions, no one, at least no economists, 
should be surprised that California would see sharp increases 
in the price of natural gas. Of course, these observations 
about the confluence of supply and demand factors is little 
solace to those who bore the brunt of higher pries, and it is 
natural to look for a scapegoat. However, based on a thorough 
review of the facts and the data, I conclude that the market 
power that has been alleged in California did not take place.
    In order to exercise market power, there has to be an 
ability to withhold supply from the market. If supply in the 
aggregate cannot be restricted, prices cannot be raised. If the 
system serving California consumers is running full and the 
suppliers put essentially every molecule of gas that they can 
into that system, then those suppliers are not exercising 
market power; and this is precisely what happened in the case 
of California in the critical 2000-2001 period.
    I think there are two major lessons that emerge from this. 
The first is that Federal rules aimed at counteracting any 
tendencies toward market power and making markets work in fact 
have worked well.
    Second, the infrastructure inadequacies in California teach 
us that Federal and State policy must maintain proper 
incentives for the investment and development of our Nation's 
natural gas delivery infrastructure.
    Thank you.
    Mr. Ose. Thank you, Professor.
    [The prepared statement of Mr. Kalt follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.067
    
    [GRAPHIC] [TIFF OMITTED] 82547.068
    
    [GRAPHIC] [TIFF OMITTED] 82547.069
    
    [GRAPHIC] [TIFF OMITTED] 82547.070
    
    [GRAPHIC] [TIFF OMITTED] 82547.071
    
    [GRAPHIC] [TIFF OMITTED] 82547.072
    
    [GRAPHIC] [TIFF OMITTED] 82547.073
    
    [GRAPHIC] [TIFF OMITTED] 82547.074
    
    [GRAPHIC] [TIFF OMITTED] 82547.075
    
    [GRAPHIC] [TIFF OMITTED] 82547.076
    
    [GRAPHIC] [TIFF OMITTED] 82547.077
    
    [GRAPHIC] [TIFF OMITTED] 82547.078
    
    [GRAPHIC] [TIFF OMITTED] 82547.079
    
    [GRAPHIC] [TIFF OMITTED] 82547.080
    
    [GRAPHIC] [TIFF OMITTED] 82547.081
    
    [GRAPHIC] [TIFF OMITTED] 82547.082
    
    Mr. Ose. Our next witness is Paul Amirault, for 5 minutes.
    Mr. Amirault. Thank you, Chairman Ose, and thank you for 
the opportunity to participate in this hearing today.
    The natural gas market in North America is very volatile. 
Natural gas is one of the most volatile commodities there is. 
California being at the end of the pipeline system has that 
volatility amplified.
    In California, the demand increases dramatically when it 
gets hot, but also when it gets cold; and it does get cold 
there, not as cold where I come from, but it does get cold. The 
demand also varies dramatically with the availability of 
hydropower.
    Hydro, nuclear and, to a certain extent, coal provides the 
base load for power generation. Gas-fired generation takes all 
of the swings. Gas-fired generation, as other panelists have 
talked about, is increasing dramatically, but not just in 
California, also in the neighboring States, outside the State's 
borders and generally upstream on that pipeline grid. So that 
adds to the volatility of the gas market in California, because 
they have competing demands outside of their borders. So the 
infrastructure problem is one of a challenge to serve a very 
volatile and peaking market.
    It doesn't make sense to build your infrastructure assuming 
that the demands will always look like last year. But it also 
doesn't make sense, and it's reassuring to see that this 
committee seems to recognize that demand won't always be like 
this year either. This is part of the cycle of demand, and this 
is a good opportunity to try and prevent the next crisis.
    What storage can do for the infrastructure is create a more 
efficient infrastructure. For existing pipeline capacity, 
storage injections provide an opportunity to make use of 
pipeline capacity when it's otherwise unutilized or of low 
value. When new pipeline infrastructure is needed, when new 
supplies need to be brought to the marketplace because the 
average day's supply isn't sufficient, then integrating storage 
into the design can help make that design much more efficient 
and cost-effective.
    Design your pipelines to meet average loads, not peak 
loads. Certainly storage can't always be found right at the 
very end of the pipeline system, but generally you can find a 
storage reservoir much closer to the market point than all the 
way back in the supply basin, so even if you have to build your 
pipeline from storage to the market to meet that peak 
withdrawal, it's generally going to be a lot less expensive 
than building your pipeline to meet the peak demands all the 
way from the supply basins. As a storage developer, we hope our 
customers get a lot of value out of storage, but storage value 
also accrues to the marketplace at large in significant 
measures.
    The pipeline efficiencies that I've just talked about lead 
to lower tolls, but when customers using storage bring their 
gas out of storage under peak conditions, if they're consumers, 
they're avoiding buying gas on the spot market; if they're 
sellers, they're selling gas into the spot market out of 
storage, and that has the effect of dampening those price 
peaks. That can be extremely significant. It doesn't have to 
just be avoiding $50 kind of gas prices, like we saw last 
winter, but even saving 30 cents for 30 days would have the 
effect of saving the PG&E noncore market, who principally buy 
their gas based on spot prices, $10 million: 30 cents, 30 days, 
$10 million.
    Also, on abnormal peak days, most jurisdictions will 
curtail noncore markets to ensure that core markets like home 
heating loads have sufficient gas. That can have a big economic 
effect. In California, a lot of that noncore market is power 
generation.
    Cutting off power supplies under cold conditions is also 
going to create its own crisis. Power plants used to have 
alternate fuel capability as a backup for such situations. 
Environmental considerations have all but eliminated alternate 
fuel capability in California. Storage should be thought of as 
the alternate, alternate fuel capability.
    Finally, market power concerns have been raised in the 
marketplace over and over. In our view, the best way to prevent 
market power issues is just to ensure ample and diverse 
competition. Storage, in effect, competes with pipelines by 
making them more efficient and therefore you need less. It also 
competes with pipeline shippers by being an alternative source 
of supplies under those peak demand days.
    To ensure the maximization of those benefits to the 
marketplace, it's important that storage transactions occur at 
the same marketplace as other trading transactions in that 
marketplace. Any toll design that separates storage from the 
market center will reduce the liquidity of the market trading 
point, and that will reduce the stability of prices.
    What can be done to encourage more storage to fit in with 
the system? In California, we have to recognize that the 
utilities that connect storage to the marketplace are also the 
competition. It's important to push for unbundling of storage 
transmission and distribution to prevent cross-subsidies and to 
prevent any conflicts of interest.
    Second, encourage interstate pipelines, encourage them to 
have efficient designs that factor in the load factor of how 
their markets will utilize their pipelines. Also to encourage 
or incentivize efficient utilization of those pipeline systems.
    That concludes my remarks. Thank you.
    Mr. Ose. Thank you, Mr. Amirault.
    [The prepared statement of Mr. Amirault follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.083
    
    [GRAPHIC] [TIFF OMITTED] 82547.084
    
    [GRAPHIC] [TIFF OMITTED] 82547.085
    
    [GRAPHIC] [TIFF OMITTED] 82547.086
    
    [GRAPHIC] [TIFF OMITTED] 82547.087
    
    [GRAPHIC] [TIFF OMITTED] 82547.088
    
    [GRAPHIC] [TIFF OMITTED] 82547.089
    
    [GRAPHIC] [TIFF OMITTED] 82547.090
    
    Mr. Ose. Our next witness is Ms. Gay Friedmann. She's the 
senior vice president, legislative affairs, for the Interstate 
Natural Gas Association of America.
    Welcome, Ms. Friedmann. You're recognized for 5 minutes.
    Ms. Friedmann. Thank you, Mr. Chairman.
    I want to say that natural gas provides 25 percent of the 
energy consumed in the United States. Since the mid-1980's, the 
regulatory structure for interstate natural gas pipelines has 
changed. Interstate pipelines no longer own the gas moving 
through their system; instead, they market capacity on their 
pipelines in much the same way that airlines sell seats on 
their aircraft.
    The cost-of-service rates charged by interstate pipelines, 
however, remain regulated by the Federal Energy Regulatory 
Commission. In the years since this restructuring has occurred, 
interstate pipelines have become more efficient, reduced their 
costs, and created and offered new services while significantly 
increasing the volumes of natural gas transported.
    The EIA and others estimate that the use of natural gas 
will increase from 23 trillion cubic feet today to about 30 TCF 
sometime after 2010. The largest area of growth, as I believe 
has been mentioned earlier, is expected in electric generation. 
In light of this increase in demand, INGAA must stress the 
importance of building new interstate pipelines.
    The natural gas pipeline industry will not support a 30 TCF 
market. There's simply not enough capacity. A study prepared 
for our INGAA Foundation estimated that our industry needs to 
invest about $34 billion in interstate pipeline structure 
between now and 2010. In 1999, $2.2 billion was expended to bid 
new interstate pipelines, and in 2000, $2.5 billion. We brought 
three brand-new pipelines into the marketplace.
    Moving to California, everyone has already talked about all 
the things that happened last year--the hotter weather, the 
colder weather, the lack of hydro in the Northwest, the lower 
storage. And this has all increased demand for natural gas by 
California electric generators, severely straining the natural 
gas infrastructure.
    Most interstate pipelines delivering natural gas to 
California end at the State line. Currently, these interstate 
pipelines have the capacity to deliver more natural gas to the 
border of California than can be taken away by the intrastate 
pipelines. While interstate natural gas pipeline facilities are 
regulated by FERC, as has been mentioned earlier, the 
intrastate pipelines are regulated by the CPUC. They are not 
required to be open access like FERC jurisdictional pipelines, 
and the CPUC has exclusive authority for approving new 
intrastate lines.
    A mismatch between capacity at the Southern California 
border and the capacity within the SoCal system is a 
significant problem in California. Unfortunately, the State of 
California has a long history of discouraging the construction 
of interstate natural gas pipelines into the State. As you have 
mentioned earlier, the only two pipelines going in right now 
are Mojave and Kern. These facilities were built in the late 
1980's and early 1990's, mainly to provide natural gas to serve 
the heavy gravity crude fields up around Bakersfield.
    The California Energy Commission has affirmed that higher 
demand, coupled with an inadequate natural gas infrastructure 
on the SoCal system, limited the ability of California to 
receive natural gas, contributing to higher prices for natural 
gas experienced in California. These higher prices reflected at 
the border were mainly the result of a premium being paid by 
nonfirm capacity customers to obtain transportation on the 
intrastate systems. When demand for capacity exceeds supply, 
price is the means to rationalize the market. SoCal is now 
increasing its intrastate capacity, as has been mentioned 
earlier, and this capacity should come on by the end of this 
year.
    INGAA wants to commend the FERC for the quick actions that 
it has taken earlier this year on a number of our member 
company proposals to build or expand capacity to and into 
California. Some of this added capacity is already completed 
and serving the California market. There are numerous 
proposals, either pending or proposed to be pending at FERC in 
the near future.
    The CEC believes that the current assumptions and 
requirements for natural gas in California need to be 
reevaluated. These include a current CPUC requirement that, 
during peaks of high demand--periods of high demand conditions, 
only the natural gas core market needs are to be met. Noncore 
markets include many large users, including electric 
generators.
    A key point made by the CEC, and INGAA agrees, is that from 
a public interest standpoint, it is better to put slack, or as 
we say, ``excess capacity'' and to pay a few cents more for 
transportation than to pay dimes or dollars more for natural 
gas supplies. While the CEC does not say it directly, they seem 
to support new interstate pipelines coming into California by 
saying a mixture of utility and privates, or so-called ``bypass 
infrastructure investments'' will help to provide the necessary 
intrastate and interstate pipeline capacity to meet 
California's future demand for natural gas.
    INGAA believes that natural gas pipeline capacity in 
California is critical. This goal can only be achieved through 
the construction and expansion of both interstate and 
intrastate pipelines in the State. Absent this additional 
pipeline capacity, California customers will never get to a 
truly competitive market and the choice in lower prices that 
such a market can provide.
    Thank you.
    Mr. Ose. Thank you, Ms. Friedmann.
    [The prepared statement of Ms. Friedmann follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.091
    
    [GRAPHIC] [TIFF OMITTED] 82547.092
    
    [GRAPHIC] [TIFF OMITTED] 82547.093
    
    [GRAPHIC] [TIFF OMITTED] 82547.094
    
    [GRAPHIC] [TIFF OMITTED] 82547.095
    
    [GRAPHIC] [TIFF OMITTED] 82547.096
    
    [GRAPHIC] [TIFF OMITTED] 82547.097
    
    Mr. Ose. We have some questions we want to go through, but 
before I get to the prepared questions, I have a couple other 
issues that I want to examine.
    Mr. Carpenter, you've got a figure 6 here in your testimony 
that talks about the flowage in the various pipelines in terms 
of percentage. But I don't see a correlative--it's not on the 
same chart, the pricing of natural gas, and as near as I can 
get it reconciled, it appears to me, if I look at figure 1 and 
try and transpose the pricing--and I guess this is the spot 
market in figure 1?
    Mr. Carpenter. That's correct.
    Mr. Ose. If I transpose the graph in figure 1 to figure 6 
to try and correlate rates of increase and percentages of firm 
capacity, I'm trying to see how close of a connection there is 
for, say, April 2000 on figure 1. It looks to be that the price 
on the spot market is around 250, and the utilization in El 
Paso is somewhere around 30 percent. Am I reading that 
correctly?
    Mr. Carpenter. Somewhat.
    Actually, I think it's a little more helpful to look at 
figure 2, because figure 2 shows the critical basis 
differential, the value of the transportation capacity, which 
is sort of the component of the delivered price that explains 
why the border price was so much higher than elsewhere in the 
country; and if you look at that figure, you see--in roughly 
April 2000 and moving into June, you started to see an increase 
in the differential from what had been a very low differential 
for easily 5 to 10 years prior to that.
    So this was the first time we ever really saw in the 
California market context, which always at least since 1988, 
had the view that they had too much pipeline, interstate 
pipeline capacity to California. And we start to diverge in 
roughly May and June, and if you look at figure 6, which shows 
the nominations and flows on the El Paso system, it's--while 
clearly, you know, El Paso was not fully utilizing or 
nominating their capacity in the March-to-May time period, 
admittedly prices were low during that period. But prices 
started to rise, and at the same time, El Paso was still not 
fully nominating, whereas every other shipper on the El Paso 
system was fully nominating.
    So our view is that the price increase experienced in 
California in the summer--in the early summer of 2000, which 
was the critical time period for filling of storage, that that 
problem was exacerbated by the fact that the capacity holder 
that has market power in Southern California was not fully 
nominating or utilizing its capacity.
    Mr. Ose. If I understand your point, then, it's that the 
groundwork for the spike in the fall of 2000 was laid in the 
spring of 2000?
    Mr. Carpenter. Exactly.
    Mr. Ose. All right.
    Now, educate me a little bit. How frequently do 
transmission lines of this nature run at 100 percent of 
capacity?
    Mr. Carpenter. Actually, most transmission lines in the 
United States run at very high, greater than 80 to 90 percent 
of load factors. All of the other transmission lines into 
California, Kern River, PGT line, Transwestern, during this 
entire period were running at a greater than 95 percent load 
factor.
    Now, that is affected by whether you have storage which 
allows you to maintain a high load factor on other pipelines in 
the country, but basically pipelines try to maintain very high 
load factors.
    Mr. Ose. So if we're sitting there monitoring flows on the 
five main lines into California, you're saying four of them 
were effectively running at 100 percent?
    Mr. Carpenter. Yes, during this time period.
    Mr. Ose. And is that the historical norm, I mean, that they 
just run flat out?
    It would seem to me that it would be if they could fill it, 
they would.
    Mr. Carpenter. Historically, El Paso has been the swing 
pipeline, and that is because it serves the most expensive 
supply basin. So naturally----
    Mr. Ose. Which would be Southern California?
    Mr. Carpenter. From the southwest producing basins in 
Texas, it's typically been the most expensive supply into 
California. So El Paso's pipeline would be the last one to fill 
up.
    Mr. Ose. So what is the historical norm for El Paso, then?
    Mr. Carpenter. Oh, if I remember correctly, sort of prior 
to the PGT expansion into California, El Paso was running at a 
fairly high load factor. Once the Kern River system and the PGT 
system were expanded, then El Paso's load factor dropped rather 
significantly.
    Mr. Ose. To what? Dropped to what?
    Mr. Carpenter. I'd have to look back at the figures. I want 
to say, on average, 60, 70 percent on an average across the 
year, but I'd have to look.
    Mr. Ose. Are there any transmission problems in any of 
these lines that you know of that would account for less than 
full utilization? For instance, did Kern River or Mojave, did 
they have a breakdown in their pumping equipment or what have 
you? Was there some other rationale that is looked at or 
explored or answered in that respect?
    Mr. Carpenter. That would explain why they had such a high 
load factor?
    Mr. Ose. As to why El Paso may have been only at 44, or 
somebody else may have been only at 80 or 92 or less than 100?
    Mr. Carpenter. OK. Well, just to be clear on figure 6, when 
we refer to EPME's nominations, we're talking about the 
Merchant Energy contract, not the load factor on El Paso as a 
whole. All other nominations up above are talking about all of 
their nominations and flows on the El Paso system. So figure 6 
just deals with El Paso.
    Mr. Ose. Was the demand on the El Paso line met by the 
flows that were on the El Paso line?
    Mr. Carpenter. Yes, but if more gas had been nominated and 
flowed, there would have been either additional demand or 
additional storage injection at lower prices during this 
period. So people were making decisions in the summer of 2000, 
do I inject into storage or do I sell gas at the California 
border?
    Mr. Ose. And yet I heard testimony from Mr. Lorenz in the 
last panel about the pricing curve, saying that people had 
anticipated further decline in prices, so they were not buying 
even though the price curve actually went the other way and it 
turned up.
    Mr. Carpenter. That's correct, and I believe that was a 
result of the withholding of capacity in the market during that 
period.
    Mr. Ose. That turn-up was?
    Mr. Carpenter. No. That it raised prices in the short term, 
yet the forward curves were still showing declines.
    Actually, if you look at the basin prices during exactly 
that same period, you didn't see the decline. You only saw the 
decline at the California border; and I believe that is a 
direct result of the withholding of capacity at the border that 
induced people to sell gas at the border at the high price, 
instead of injecting it into storage.
    Mr. Ose. If I have capacity in pipeline, how long in 
advance do I go through the nomination process?
    Mr. Carpenter. On the El Paso system, there's four cycles 
of nominations. Two of them occur the day before the gas flows, 
and there are two that occur on the day that the gas flows.
    Mr. Ose. So it is almost contemporaneous?
    Mr. Carpenter. It is.
    Mr. Ose. All right. So there's no time lag in that respect? 
And there are no transmission problems on the line that would 
otherwise result in a reduction of its capacity, that you're 
aware of?
    Mr. Carpenter. Well, in August, we did have the Carlsbad 
explosion, which did reduce capacity.
    Mr. Ose. By how much?
    Mr. Carpenter. For a 2-week period, it was roughly 700 
million a day, I believe. And then there was a longer-term, 
permanent--or longer-term reduction of 250 million a day for 
safety reasons that continued through the year. But again our 
evidence indicates that there was still available capacity on 
the El Paso system that could have been utilized if Merchant 
Energy had chosen to nominate and flow its gas.
    Mr. Ose. What I'm trying to get at--I mean, 44 percent kind 
of just jumps off the page at you. I'm trying to watch out for 
all of the adverse occurrences to get to what it would have 
been under an optimal scenario.
    Now, the reduction in flowage from August forward would 
have accounted for something. Did El Paso Merchant accept the 
entire burden of that reduction, or was it apportioned amongst 
all of the people conveying gas through the pipeline? Do you 
know the answer to that?
    Mr. Carpenter. Well, if you look at figure 6, for example, 
you'll see that in the August time period, if you look at all 
others' flow, there was a reduction in other people's flows, as 
well, during that period. And those people were nominating at 
100 percent all across the board.
    The curious question in my mind that has never been fully 
explained is why El Paso Merchant was not nominating 100 
percent. Why were they not even trying to get as much of their 
gas into the market as they could?
    And the explanation during this summertime period can't be 
that, oh, there wasn't a market for it. Relative to historical 
standards, prices were extremely high, so there would be a 
market for people willing to take the gas at a slightly lower 
price, believe me.
    That is the case.
    Mr. Ose. If the total capacity of the pipe is 100, El Paso 
Merchant's share of that 100 is how much?
    Mr. Carpenter. About 35 percent.
    Mr. Ose. So if it's 35 percent, and they're only running 44 
percent of that, they're at somewhere around 15 percent of the 
overall capacity?
    Mr. Carpenter. Right. It's about, on average, I think about 
400 to 500 million a day of unutilized capacity during this 
summertime period, which is almost equivalent--if you think of 
the Kern River pipeline, that is a 700-million-a-day pipeline, 
so it's like that much--you know, two-thirds of that capacity 
being pulled out of the market.
    Mr. Ose. All right. So if they're running at 15 percent of 
the pipeline capacity and they have basically idle 20 percent 
of their share, and everybody else is running flat out, that 
means 80 percent of the pipe is being used?
    Mr. Carpenter. Yes. Although even on the El Paso system, 
even everybody else when they nominate 100, they--they're lucky 
if they're able to get, you know, 85 to 90 percent flows. You 
can see that if you look in the winter of 2001, where everybody 
acknowledges that the system was maxed out. People are 
nominating 100 percent, but they're getting, you know, 80 to 90 
percent flow rate.
    Mr. Ose. So, in any case, the pipe is not running at 100 
percent anyway? I mean, nobody is using--other than, say, let's 
see, here in December 2000 and February 2001, those are the 
only 2 months people are running at 100 percent. Again, I'm 
trying to understand, is the amount of gas that was going in 
the pipeline that El Paso Merchant was part of combined with 
the amount of gas coming through the other pipelines going into 
the State, was that adequate to meet demand; and if it was, I'm 
trying to understand why El Paso Merchant would only run at 44 
percent? I just----
    Mr. Carpenter. And the reason why they would do that is 
because, by doing so they would be able to raise the price at 
the border and be able to sell gas at the border at a higher 
price.
    Mr. Ose. And it's your contention, if I read your testimony 
correctly, that they did it for the purpose of raising the 
price at the border and that there was collusion amongst 
everybody on the line?
    Mr. Carpenter. No. There doesn't need to be collusion. The 
issue that I address there is the question of whether or not 
everybody else was fully utilizing their capacity, which was 
something that the judge theorized was the case. And, again 
looking at figure 6, pretty much during this entire period of 
the El Paso contract, all other shippers were nominating--were 
attempting to use all of their capacity.
    So to say that during this period, say, if you look at July 
when El Paso was nominating about half of its capacity and 
flowing about 40, 45 percent of its capacity, during that 
period to say, oh, well, all others could have nominated and 
shipped more, is just incorrect.
    Mr. Ose. Because according to this chart, they're 
nominating at 100 percent, even though they're flowing at, say, 
83 or 84 percent.
    Mr. Carpenter. Right. The flowing aspect of the El Paso 
system is a feature of the fact that there's--it serves a 
couple of supply basins, and there's some complicated 
allocation questions, so that nobody ever seems to be able to 
get 100 percent of their nominations, except in some months.
    Mr. Ose. Now, Professor Kalt, your testimony on page 8 says 
that basically this market power that might be embedded in El 
Paso Merchant does not exist, or more accurately, has not been 
the source of the natural gas crisis in California. So you have 
a wholly different view.
    Mr. Kalt. Well, my colleague and I did testify on opposite 
sides in this matter, and I think the data do indicate 
otherwise, yes.
    Mr. Ose. How do you reconcile the issue of an increase in 
price versus 80 percent basically of the pipeline capacity 
being utilized?
    Mr. Kalt. Well, in the discussion you just had, I think 
there are at least two additional critical facts that would be 
helpful to your understanding.
    One is that El Paso Merchant Energy, the marketing arm, 
held this capacity in a number of different blocks; and without 
going into all the details, with respect to El Paso pipeline 
capacity, the marketing company had three critical blocks. One 
of those blocks was equivalent in its security, its firmness, 
to what other parties held. But two of the blocks were not as 
secure; they could be bumped off the line.
    Mr. Ose. You're talking about the other parties who were 
nominating for capacity?
    Mr. Kalt. Yes, yes. And two of the blocks that El Paso 
Merchant Energy held were lower priority service, and when we 
look at the nomination strategy as the demand in California 
picked up, as I detailed in my testimony, and the pipeline 
began to fill what you saw was, not surprisingly, the parties 
with the best quality were able to get into the market first.
    When El Paso Merchant Energy had capacity of equivalent 
quality with the other shippers, what we see is behavior that 
mirrors those other shippers. They tend to nominate quite 
comparably.
    Mr. Ose. You've looked at the empirical data that says when 
you have apples and apples in terms of transmission capacity, 
everybody was behaving the same?
    Mr. Kalt. In terms of firm transportation capacity.
    Mr. Ose. Apples and apples?
    Mr. Kalt. Apples to apples, yes.
    Mr. Ose. Everybody was behaving the same.
    Mr. Kalt. Well, there are differences, but you do not find 
this 44 percent difference. What you find is that El Paso 
Merchant Energy, for example, on its most secure capacity, it 
nominates 100 percent, and it tries to nominate and push gas 
through the system just like everyone else, when you look at it 
on an apples-to-apples basis.
    Mr. Ose. It was in the other blocks or the other--the 
inferior tranches of capacity that they did not meet or did not 
utilize their entire allocation, so to speak?
    Mr. Kalt. When you look at the empirical data, if you look 
at those other tranches or blocks, the less secure quality 
capacity that El Paso Merchant Energy had, that's what 
generates these kinds of numbers that have been thrown around 
like 44 percent.
    I mentioned that there were two critical factors. A second 
critical factor is important to get on the table. Beginning in 
the summer of 2000, the shipments that were being nominated on 
the El Paso system, the nominations began to be cut as the 
capacity of the system was strained. In other words, parties, 
all parties attempting to push gas through the system found 
themselves being cut, I think you earlier asked Dr. Moore if 
the capacity was actually they found themselves trying to push 
more than X in the system and the nominations began to be cut, 
what that tells us is that it's not an artificial restriction 
in supply by one of the shippers, but rather the system itself 
is having trouble getting that gas through to California 
customers.
    So I think when you add in those--at least those two 
critical facts, I think a very different story emerges, and it 
tells you that you faced infrastructure constraints in the 
summer of 2000 and on into the winter.
    Mr. Ose. How much of these inferior tranches, or how much 
of the demand represented by the inferior tranches of 
allocation represent noncore customers in California?
    Mr. Kalt. I don't know if we have that data, sir.
    Mr. Ose. It would seem to me that would be a highly 
variable demand, if it's noncore and it's nonfirm.
    Mr. Kalt. Sure, you would think that it would. I don't know 
if we have the data exactly. The utilities themselves who serve 
their core customers, PG&E and SoCalGas, are essentially large 
shippers on the system, both on their own account and in some 
cases they have purchased capacity from others. But they are 
shippers, as well, on the system.
    Mr. Ose. I'm going to get to you. Be patient.
    I want to go back then, Mr. Carpenter, in terms of the 
capacity on that line that El Paso Merchant was participating 
in, that line was delivering gas to the border and that gas, at 
the border, was then put into an intrastate pipeline based on a 
nomination process that favored certain customers, core 
customers over noncore customers. I mean, that was the 
testimony from Mr. Lorenz; I think also Ms. Lynch.
    Are you familiar with the nominating process of the gas 
going into the intrastate lines?
    Mr. Carpenter. Yes.
    Mr. Ose. Is there any connection between the manner in 
which the nomination process is made on the intrastate line to 
the capacity utilization on the interstate line?
    Mr. Carpenter. I think, in answering that question, you 
need to distinguish between northern and southern California.
    Mr. Ose. It does so happen I have right here in my notes to 
ask about that distinction.
    Mr. Carpenter. In northern California, PG&E has unbundled 
its high pressure transmission system, which they call the 
backbone, and the way that they have done that and the way that 
they conduct nominations and scheduling on the backbone is very 
much like an interstate pipeline, in the sense that if you're a 
shipper, you can hold firm capacity on the PG&E backbone, and 
you can trade it just like you can hold interstate capacity, 
and you can trade it. So it makes for a relatively seamless set 
of transactions into the heart of the demand centers in San 
Francisco.
    Mr. Ose. So far, greater certainty on that side?
    Mr. Carpenter. Yes. And with respect to the SoCalGas 
system, they have not as yet unbundled. They treat their 
transmission system as part of their local distribution 
network, and so when you nominate into the SoCalGas system, 
essentially you're not utilizing a transportation right that 
you have on the high pressure part of their lines; you're 
nominating for the ability to get into the system and have your 
gas delivered via local distribution service or all the way to 
the burner tip.
    And because there are some points on the SoCalGas system 
that are more valuable than others from a market point of view. 
There has been this tendency historically to load up 
nominations on the relatively more valuable points. One of them 
is called Topock, or Wheeler Ridge, which is the connection 
between PG&E and SoCalGas's system. That is where Kern River 
comes in, and SoCalGas then allocates in a prorationing form 
approach, which they call ``windowing.'' They allocate those 
rights into the system, and it's been my sort of firm 
conviction for a number of years now that process in southern 
California creates some inefficiency that could be rectified if 
the system was unbundled in the way that PG&E, for example, had 
unbundled its system, and that you'd have a more consistent 
statewide network.
    And, in fact, there was a proceeding, which I participated 
in at the California commission, which investigated exactly 
that question, and a settlement had been reached which would 
have done partly that. And that all got caught up in the 
electricity crisis and basically hasn't moved forward as yet. 
But I think you heard Commissioner Lynch mention that those 
issues are still on their docket.
    Mr. Ose. Was there enough capacity at the border? If El 
Paso Merchant had run at something in excess of 44 percent, was 
there enough take-away capacity at the border to take the gas?
    Mr. Carpenter. Yes, during the summer period, in my 
judgment. And if storage had been filled as a result, our 
calculations indicate there would have been enough capacity in 
the winter to meet even the winter peak.
    You have to remember that in southern California, gas is 
still winter-peaking; the highest demand is in the winter. So 
the system was fully--should have been capable of taking that 
additional gas in the summertime. And I believe Mr. Lorenz has 
so testified. And if storage had been filled, the system would 
have been able to meet the winter demands, as well, without 
reaching capacity constraints. Unfortunately, we didn't have 
that situation.
    Mr. Ose. But that gets to the pricing curve that Mr. Lorenz 
related.
    Mr. Carpenter. And whether the withholding of capacity 
directly influenced that border price curve, which I believe it 
did.
    Mr. Ose. Professor Kalt, you don't agree?
    Mr. Kalt. No, I don't think that is accurate on two counts.
    And the FERC has been presented with an analysis of this. 
Both of the conditions that Dr. Carpenter just mentioned, 
filling the storage and servicing the growing demand and 
booming demand that was going on in California, they both 
couldn't be satisfied. When you look at the data, the data 
indicate that you could not fill the storage and satisfy the 
demand and keep the prices at the historic levels that were 
talked about earlier.
    The binding and constraint in that analysis turns out to be 
inside the State system. It can't get enough gas in. The simple 
reality is that California found itself in a situation in which 
summer, normally a storage-fill period, demand boomed. And then 
winter came on, and then November 2000 was the coldest winter 
in 90 years. It started out that way. California never got a 
breather to go fill that storage, and so it hit the winter with 
a situation in which demand remained very high in the winter 
and storage had never been filled.
    Second, I think that the analysis of the price curve is 
wrong. That price curve is a statement of people's 
expectations. El Paso Merchant Energy was known by the 
marketplace to have this capacity. It was going to have that 
capacity through the storage-fill season on into the winter. If 
it thought that there was market power going to be exercised, 
there was no reason not to exercise that. And El Paso Merchant 
Energy wasn't going to give up its capacity in the middle of 
the summer of 2000. It was known it would have that capacity.
    But I think the basic reality is that California found 
itself in the situation--it was described earlier as ``the 
perfect storm''--where it never got a breather to go fill that 
storage, and the demand simply outstripped the capability of 
the system to fill storage and service demand.
    Mr. Ose. Mr. Amirault, on page 4, in the second-to-the-last 
paragraph, you talk about the economic advantage that both 
pipelines get from adding rate base and that poor utilization 
of the firm contracts basically helps the shareholder. In other 
words, you do a bad job, your shareholder's benefit, I think, 
is the connection.
    I'm asking something that is almost implicit here, and if 
I'm wrong, you need to correct me, but are you saying that the 
structure of the contracts, that being the core versus noncore, 
or the manner in which they're nominated for, are you saying 
that structure is one of the root causes of the pricing 
structure?
    Mr. Amirault. It's not the core versus noncore aspect; it's 
the contract capacity aspect of it and the fact that pipelines 
get the bulk of their revenue through demand charges that are 
reservation charges paid by the shipper, whether they use that 
capacity or not. So a pipeline in its business is getting a 
return on rate base.
    To the extent it can make a proposal to shippers, get 
shippers to sign up for long-term contracts where they're going 
to pay reservation charges for that full term whether they use 
the capacity or not, that assures the pipeline of a reasonable 
return on its investment. Then the company says, OK, that base 
return is covered. The pipeline says, I'm good for 10 years, 
I've got a return on my investment; how do I go and generate 
incremental revenue?
    And toll designs have encouraged looking for incremental 
revenue with mechanisms that share that incremental revenue 
with the shippers. It will reduce the tolls for the shippers if 
they can generate some incremental revenue, but to encourage 
that, they also give some of it to the pipeline shareholder in 
an incentive ratemaking scheme. So the net result is that the 
system is set up so that a pipeline is advantaged by 
encouraging a design that becomes inefficient, where the people 
that are paying the basic return aren't going to effectively 
utilize that capacity so that, in turn, they can generate some 
more revenue and get an extra return for the shareholder.
    It may appear that the tools, the base tools, are lower 
than they would be otherwise, because the pipeline will say, 
the more I can get, the lower average toll I can charge. That's 
because they're charging that average toll over some capacity 
that is not being very effectively utilized by the firm 
shippers paying for it. The industry as a whole is paying more 
money to the pipeline company than they might need to if there 
was a more effective design.
    Mr. Ose. I'm thinking about what you just said.
    So in effect, you basically have, if you will, an annuity, 
which is the standby charge, and then you're trying to add 
little bits and pieces over time to that annuity to increase 
your returns, and the pipeline owner, in effect, is willing to 
split that with the gas purveyor to their mutual benefit?
    Mr. Amirault. That's right. It's as if a hotel sold a block 
of rooms to a corporation for 10 years, and knew that the 
corporation would only use it 75 percent of the time. So they 
go and resell some of those rooms to other parties.
    Mr. Ose. Statistically, they're going to be OK on that 25 
percent?
    Mr. Amirault. That's right.
    Mr. Ose. All right. Now, your storage facility, you buy gas 
for storage, and then you basically wheel it back into the 
system on demand. You're buying gas on long-term contract?
    Mr. Amirault. No. Essentially we're a service provider. 
We're a warehouse. We sell space in our warehouse to third 
parties.
    Mr. Ose. Third parties who own the gas. They come to you 
and they say, Mr. Amirault, we want one-third of your tank?
    Mr. Amirault. Right.
    Mr. Ose. OK. And then depending on their demand, they will 
wheel that one-third out to meet whatever vagaries they have in 
their demand?
    Mr. Amirault. That's right. If they're a consumer, they 
will store gas when they can buy it more cheaply than they 
expect to have to pay at times when their demand peaks. If 
they're a seller, they will store gas when prices are low so 
that they can try and sell it and withdraw it and sell it into 
markets when prices are higher.
    Mr. Ose. The gas that you have in storage, does it come 
from a single source or a single pipeline, or do you get it 
from multiple sources?
    Mr. Amirault. We're connected to the PG&E pipeline system, 
and so any gas that our customers put into our storage facility 
has been transported over the PG&E pipeline system, and when 
it's withdrawn, it is withdrawn onto the PG&E system.
    Mr. Ose. All right. Do you know--in terms of the intrastate 
practices on pricing, educate us a lit bit about northern 
versus southern California. I mean, I can look at electricity 
prices and there is a constant differential of some 50 to 60 
cents per megawatt between NP-15 and SP-15. Does that same kind 
of differential exist for natural gas?
    Mr. Amirault. There has been a similar differential between 
the northern California and the southern California 
marketplaces. What that can be ascribed to may be a number of 
factors. I suspect part of it is the unbundling of 
transportation on the PG&E system that hasn't occurred yet on 
the SoCal system. So that there is a city gate market on PG&E, 
and the city gate is after the transmission from the California 
border to the load center near San Francisco. There is an 
effective marketplace there. People pay their transportation 
toll to get to that city gate market center, and then they can 
transact business with end-use customers.
    Mr. Ose. You're suggesting there's a competitive advantage 
to coming across the PG&E line versus going into southern 
California.
    Mr. Amirault. The end-use customer, I think, has benefited 
marginally in northern California, yes.
    Mr. Ose. Is that competitive advantage that goes to the 
retail customer a function of the manner in which SoCalGas 
handles its nomination process, or its contracts, for use of 
its pipeline?
    Mr. Amirault. Well, it's a function of the different market 
structure in SoCalGas territory. I believe that's so because 
they don't have unbundled transportation from the border to a 
city gate; customers can't contract for transportation and be 
assured that their volumes will move on their capacity without 
a potential prorationing and this windowing effect.
    In northern California, customers can contract for firm 
capacity from the State's borders to the city gate. And when 
they nominate it, they can be assured it will flow; it won't be 
prorationed. There is a difference.
    Mr. Ose. Mr. Lorenz was talking about the lack of 
construction of generating facilities in southern California. 
Is this the root cause of it? Is this a differential of firm 
capacity?
    Mr. Amirault. I could only speculate on various causes for 
that. It may be, as you described it, a power value difference.
    There's a constraint across this path 15, which can make 
power more valuable north of that path, as I understand it. It 
may be siting considerations, environmental considerations, 
making it difficult to site. It may be the general business and 
regulatory climate in the State has encouraged parties to 
locate sites outside of the city.
    Mr. Ose. Just a moment, please.
    Mr. Carpenter, one of the things we've struggled with is 
quantifying natural gas demand in northern California, natural 
gas demand in southern California versus interstate capacity 
for transmission of gas into northern California, interstate 
capacity of natural gas into southern California and then 
intrastate capacity north and south for distribution.
    Do you have any data indicating how that dynamic plays out? 
How does demand compare to supply in northern and southern 
California?
    Mr. Carpenter. Yes. We have that kind of information. It's 
a difficult question to generalize about and a difficult 
question to analyze, because you need to decide whether you're 
going to talk about averages, annual averages or whether you're 
going to talk about system peaks, because they're different in 
the different parts of California. So it's a multifaceted 
question, you're asking me, and there's not a simple answer.
    Mr. Ose. Would you like to do it in writing instead? I 
mean, that might be easier.
    Mr. Carpenter. I'd be happy to, and it also gets to this 
question of whether there's a mismatch between inter- and 
intrastate capacity. I actually don't believe there is a 
significant mismatch, and many of the comparisons you see don't 
adequately take into account the pipelines that cross the 
border, Kern River and Mojave, and when they make those 
calculations----
    Mr. Ose. We're going to ask the same question of Professor 
Kalt, too, so we're going to get both perspectives here.
    Mr. Carpenter. OK.
    Mr. Ose. Now, if I might go on, Mr. Waxman, I thought, 
brought up an excellent observation regarding the June 2001 
expiration of the El Paso Merchant contract; and he ascribed 
the decline in prices to the relinquishment of the contract.
    The question I have is--and maybe it's purely coincidental, 
but FERC's market mitigation plan actually kicked in on May 
29th, a couple of days prior to the expiration of the El Paso 
Merchant's contracts. I'm trying to get a better feel for 
whether or not, given the relationship between natural gas and 
electricity, whether the decline in prices at the end of May or 
the first of June was a function of FERC's market mitigation 
plan or the relinquishment by El Paso Merchant of their 
contract; and I'd appreciate any input from any of you on that.
    Mr. Carpenter. I would venture to say that it's some of 
both, for the following reason: With respect to the Merchant 
capacity, the fact that you went from one seller holding a 
billion-and-a-half cubic feet a day to 25 sellers holding that 
capacity and competing to provide it had to have an impact.
    The reference to the mitigation plan I think is important, 
too, in the sense that one of the problems that we had in 
California that resulted in the ability to exercise market 
power in the way that was done, in my view, is that demand for 
gas was very inelastic by power generators, in part because 
there wasn't a mitigation plan in place. Once the mitigation 
plan is in place, in my view, the elasticity of demand--in 
other words, the responsiveness of the buyer to price, 
increases. And so I think you could also ascribe some of the 
effect to that happening at that time. But I think it is very 
important to recognize that--we all went into the summer 
expecting the prices to continue to be high.
    In fact, Professor Kalt was making the argument at the time 
that the forward price for gas, which continued to show high 
prices through the summer, that was an affirmative indication 
that El Paso didn't have market power. When he will, the 
reality was that when the contract was actually relinquished, 
the prices fell. So I don't think you can overstate the 
importance of that as well.
    Mr. Kalt. I think the discussion here got off on the wrong 
foot, in that Mr. Waxman was provided with incorrect 
information. He said a couple of times--he's not here, but he 
said a couple of times that prices began to decline in June. If 
you look at figure 1 that I attached to my testimony, you'll 
see that, in fact, as demand began to soften in California when 
you got into the springtime, there's been a downward trend in 
California prices since about April, and that downward trend 
continued on out into sometime, it looks like in September.
    And so that downward trend, if you look at June where you 
see a bunch of spikes there, I think it's just bad science, if 
you will, to try to pick out a single spike and say that is the 
end of some market power. I think what you see is a market that 
is going through a lot of turmoil. Demand is softening, but 
prices did not return to the level predicted by the market 
power theory.
    On a consistent basis, it's really out in September, 
sometime within about the last month when prices have really 
come down to their historic levels, and that downward trend 
is--just as I said, it's sort of bad science to pick out May 
29th or June 1st. We were in a situation, as I detail in my 
testimony, where demand was gradually softening in California, 
and I think prices reflect the supply/demand forces in that 
trend.
    Mr. Amirault. If I could just add a few other comments, I 
think that there were many other factors that also contributed 
to the time of that price decline.
    A similar-shaped curve happened to North American prices, 
as Professor Kalt shows in his testimony he just referred to, 
so the North American price curve was falling in the same 
pattern. As I described, the volatility is amplified in 
California for various reasons, but it was driven by a lot of 
North American supply/demand factors.
    Supply was increasing in the North American supply basins 
in response to the price run-up that had occurred the previous 
fall and winter; that supply was coming on. Demand was 
decreasing across North America. Many industrial consumers 
decreased their consumption of natural gas because it had 
gotten too high-priced. That was accentuated in California's 
economy with the downturn in the technology sector. To use the 
``perfect storm'' analogy again, it was almost a perfect storm 
of market events in the opposite direction that occurred in 
2001, as occurred in 2000 in many factors.
    Mr. Ose. I mean, it's almost pure Adam Smith response, 
invisible hand reaction.
    Mr. Amirault. The market was working.
    Mr. Ose. Mr. Carpenter, I'm confused by something in your 
testimony. You say that the pipeline capacity in southern 
California, along with the SoCalGas storage withdrawn capacity, 
exceeds that of the peak southern California gas demand in 
January 2001.
    I mean, am I correct on that?
    Mr. Carpenter. Yes. The system's capability substantially 
exceeds the peak demand that was experienced in January 2001. 
Again, conditional on the gas actually being in the storage 
inventory to be available to be withdrawn, this is the capacity 
if it had been full.
    Mr. Ose. The aggregate capacity between interstate 
deliveries and storage?
    Mr. Carpenter. That's correct.
    Mr. Ose. Now, on that day, interstate deliveries at the 
border may have been some amount, and draw and storage may have 
been a different amount. It's your testimony that the take-away 
capacity at the border was sufficient to handle whatever came 
in and that the intrastate system was sufficient to handle 
whatever was drawn out of storage, if it had been there?
    Mr. Carpenter. Yes. That system was sized to handle roughly 
a 7-BCF-a-day peak, or 6.5-BCF-a-day peak. This is what figure 
4 shows. And the peak on the SoCalGas system was about 5.2 BCF 
a day.
    Mr. Ose. All right. Let me just take a moment here.
    Mr. Amirault, there's something we've just been struggling 
to figure out, how this gets quantified, gas flows into a 
storage facility.
    You guys hold it. A third party owns it. Then demand rises, 
and the retail purveyor draws that--I mean, that gas is drawn 
out for demand. There is a cost of moving it from the storage 
facility back into the distribution system for the end-user.
    What is that added cost of transportation, and how is it 
factored in? That is a CPUC decision, I presume.
    Mr. Amirault. It is, and in PG&E's toll design, where we're 
situated, the effect is that storage customers pay the 
transportation toll on the way into storage, and they don't pay 
that transportation toll again to come out of storage. So the 
storage----
    Mr. Ose. You pay to divert, but you don't pay to put back 
on, so to speak?
    Mr. Amirault. You pay that transmission toll once, even 
though you're dropping off partway between. You pay it on the 
way in; you don't pay it on--you don't pay it again on the way 
out. You effectively paid for the whole path on your injection 
leg.
    Mr. Ose. And that's a tariff set by PUC?
    Mr. Amirault. Yes.
    Mr. Ose. All right.
    Mr. Amirault. And that is a good design in my view, because 
it makes those storage transactions not differentiated by a 
toll from the city gate trading point. So they're adding to the 
liquidity at that city gate market trading point.
    Mr. Ose. From your experience--well, you had to locate 
wherever you located because that is where the geologic 
structure was. But the manner in which PG&E handles its 
transmission into your facility relative to how transmission 
into a storage facility might be handled by SoCalGas, besides 
the geologic or the geographic difference that you have, do you 
have a preference or any insights you might offer us as to 
which is a better way of doing it?
    In other words, is the ``unbundled'' manner in which PG&E 
handles it preferable to the manner which SoCalGas handles 
theirs; or is it vice versa?
    Mr. Amirault. You can't move the reservoirs. They are where 
they are, and this was the best reservoir we could find in 
California.
    But the CPUC's storage decision of 1993 said that there 
wouldn't be duplicate tolling for storage. They encouraged the 
utilities to design their toll structure so that you wouldn't 
pay a duplicative toll. You wouldn't pay coming out what you 
already paid coming into storage. So even though SoCal's toll 
structure is different in that they haven't unbundled their 
transmission, presumably if somebody developed an independent 
storage facility on their system, somehow that same effect 
would be accomplished. You won't pay twice.
    The advantage to the PG&E system, in my view, is the 
unbundling, the clear separation of transmission from the other 
bundled storage services provided by the utility and the 
distribution service provided by the utility. That is much more 
clearly separated in PG&E's structure than it is in SoCal's 
structure.
    Mr. Ose. Ms. Friedmann, I hate to put you on the spot, but 
I'd be curious about what INGAA thinks. Is there a preference 
amongst your members for the manner in which capacity is 
nominated?
    Ms. Friedmann. I don't know.
    Where did she go? I was just looking for our general 
counsel.
    Mr. Ose. I mean, if you don't have a position, just tell 
me.
    Ms. Friedmann. I think you know, we have a process that we 
use on the interstate system. The way our process works, when 
we want to build new pipeline, what we do is we go out into the 
marketplace, and we ask--we have what we call an ``open 
season.''
    Mr. Ose. Right.
    Ms. Friedmann. And what we're trying to do is ascertain 
whether there are customers out there to build--who would want 
this capacity, and once we find that we have enough of that, 
then we will go off and build whatever there is that we think 
we need.
    Mr. Ose. Well, I mean, you're begging this question. I'm 
going to ask it. It would seem to me that some of these 
generating facilities that rely on natural gas----
    Ms. Friedmann. A great many.
    Mr. Ose [continuing]. To fire their turbines, from a 
technological standpoint are far more efficient, say, than some 
of the existing infrastructure. In other words, new is better 
than old in terms of converting BTUs to electricity, and for 
the benefit of the consumer, that conversion ratio, the higher 
we can make that conversion ratio, the lower the price of the 
end-user.
    The question you beg is, why wouldn't we set it up so that 
someone who is using huge amounts of natural gas as their base 
fuel to run a highly efficient technologically advanced 
generating facility relative to, say, some of the existing or 
older facilities, why wouldn't we make it possible for them to 
directly contract for interstate delivery?
    Ms. Friedmann. Now you're talking about California. We 
basically, elsewhere in the country, are doing that right now. 
We have numerous pipelines out there. A lot of this 30 TCF that 
I mentioned in my testimony is new electric generation 
throughout the country; and as you have seen, there are a 
number of instances where we have even had mergers of 
interstate pipelines with electric utilities, and part of that 
value is because the electric utilities then want to build 
along the interstate pipeline system these new highly efficient 
plants.
    All of our member companies are out there right now seeking 
those kinds of customers and saying who is willing to, who is 
not; there are a lot of people out there right now looking at 
building electric plants. Not every one of those plants is 
going to be built. We want to find the people who are willing 
to sign those contracts, and we are eager to then build the 
capacity to help serve them; and we have worked for the last 
few years to acquire the flexibility in our system in order to 
accommodate that service.
    Mr. Ose. Now, does the matrix under which you're operating, 
or the dynamic under which you're operating, account for the 
decline in deliveries to the end of the pipeline off of 
existing infrastructure if you locate that generating facility 
someplace outside California?
    In other words, whatever the pipeline is, currently it's 
delivering X to California. If you put another straw in the 
pipeline, say, in Arizona, the pipeline still only has X 
capacity. I mean, does your matrix account for that----
    Ms. Friedmann. That basically is something that each 
pipeline looks at. But, for example, I know Kern River is now 
proposing to build a significant expansion into California.
    One of the reasons they are doing that is because they are 
not able, I believe--and I want to be careful that I'm saying 
this as Gay Friedmann and not as Kern River--but they have had 
that circumstance where they have a number of electric 
generating facilities in Nevada, and, therefore without new 
capacity, they are not able to serve--fulfill all their 
capacity to California. Therefore, they are going to increase 
their capacity in order to meet new anticipated demand out 
there, as well as serve their customers between California and 
Wyoming.
    Mr. Ose. Is the process working now, today, to 
expeditiously accomplish that goal? Is FERC working----
    Ms. Friedmann. FERC, I would say, is doing very well. I 
really commend the Commission. They have been working very hard 
to try to expedite the building of interstate transmission 
facilities. And we have a lot of applications; I have a number 
of them just here that are pending right now before FERC.
    Mr. Ose. Would you like to enter those in the record?
    Ms. Friedmann. Sure.
    Mr. Ose. OK. We'll do that.
    Ms. Friedmann. Sure. OK. Pardon my writing. We'll get you 
cleaner copies, but----
    Mr. Ose. That's all right.
    Ms. Friedmann. Then you can show Mr. Shays that indeed 
there are a number of pipeline proposals up in the New England 
area.
    [The information referred to follows:]
    [GRAPHIC] [TIFF OMITTED] 82547.098
    
    [GRAPHIC] [TIFF OMITTED] 82547.099
    
    [GRAPHIC] [TIFF OMITTED] 82547.100
    
    [GRAPHIC] [TIFF OMITTED] 82547.101
    
    [GRAPHIC] [TIFF OMITTED] 82547.102
    
    [GRAPHIC] [TIFF OMITTED] 82547.103
    
    Mr. Ose. All right. I want to finish on one particular 
question, very similar to what I asked the last panel; and 
we'll just go right across the panel.
    Notwithstanding the differences to the capacity issues and 
all that, Congress has a charge. Obviously we want gas 
delivered where there's demand. We want the people who deliver 
the gas to be able to survive. We want the end-users to have 
the product they need.
    What, if anything, should Congress be doing to address the 
issue of infrastructure, whether it be pipelines or storage, to 
meet the demand for natural gas in this country?
    Mr. Carpenter.
    Mr. Carpenter. Yes. I think the watchword I would suggest 
is market monitoring, and the reason I say that is because we 
have a regulatory regime in place at the Federal level that 
relies to a great extent on competition between the holders of 
pipeline capacity to ensure that it's efficiently utilized and 
to send the price signals to the market for when pipeline 
capacity should be expanded.
    That regulatory regime, to be effective, has to have in 
place a mechanism whereby it can monitor for the potential 
presence and exercise of market power. It didn't need to do 
that under the old regulatory regimes, cost-of-service-based 
regimes. You do need to do it now in natural gas markets.
    I think Commissioner Wood--and I commend him for his 
approach with respect to the strategic plan that he's put 
forward that emphasizes market monitoring, and I think the 
situation in California perhaps, we hope it's unique, that it 
will never happen again, but I think it was a classic case 
where the prior regulators didn't see the signals that were in 
the market. As far back as when Dynegy held that block of 
capacity on the El Paso system, and the regulator was apprised 
of the fact that there was a market power problem that could 
potentially create the situation that occurred.
    So the watchword, from my point of view, would be market 
monitoring, and the kinds of hearings that you're having here 
which emphasize that, I think are important.
    Mr. Ose. Before we go to Professor Kalt I want to followup 
on one thing, would you support or oppose--let me phrase it the 
other way. As it relates to the different State's PUCs, in 
terms of the tools to be given to utilities to address their 
power needs, do you support or oppose giving utilities the 
ability to forward contract at their own economic risk?
    Mr. Carpenter. Oh, I support it wholeheartedly. I think 
that's a very important tool to have in place. But it has to be 
watched. If the utility is in a position where it could--it has 
an information advantage or some advantage that another market 
player doesn't have, that could create a potential for market 
manipulation.
    Mr. Ose. Which gets to that monitoring issue.
    Mr. Carpenter. Exactly. Exactly.
    Mr. Ose. What percentage of an overall utility's power 
production portfolio do you think should be dependent upon the 
spot market? Or I could do it the other way. What percentage do 
you think should be dependent upon either in-house production 
or forward contracting?
    Mr. Carpenter. That is a difficult question to answer in 
the generic sense, because I think it depends on the kind of 
generating equipment they have, how much they're relying on 
their own generation versus buying from merchant generators. In 
other words, how exposed are they to the fuel price risk that 
your question implies some need to mitigate, so----
    Mr. Ose. Why don't we give you that question in writing and 
you can respond accordingly.
    Mr. Carpenter. And we may have to refer to some specific 
circumstances to be more precise about that. We can at least 
talk about how you would analyze that question.
    Mr. Ose. The reason I ask it is, in California, the 
direction given to the utilities was they wanted to increase 
their reliance on the spot market while at the same time 
removing their ability to forward contract to cover their 
exposure. So, I mean, it's something very near and dear to my 
interest.
    Mr. Carpenter. Yes.
    Mr. Ose. Professor Kalt, same question. What should 
Congress be doing?
    Mr. Kalt. Let me address that from the Congress's 
perspective.
    I think--first, I'm sort of surprised in this hearing. 
Actually, you hear a fairly unanimous view that FERC is on the 
right course, and I agree with that. I think that hearings like 
this are important. As Dr. Moore said, these kinds of oversight 
hearings allow for an airing of the issues; but just as 
importantly, they give muscle to the policy and send signals 
throughout the system as to the interest of Congress.
    Third, I would echo something that Dr. Moore said in the 
first panel. And that is, in terms of infrastructure 
investment, it remains the case that the NIMBY problem, not in 
my backyard, continues to sit there and cause delays, expense, 
risk, all of those things discourage investment.
    That is not to say in any way, shape or form we should put 
the environment at risk. But we continue to need to work on it 
in this country. And it occurs at the State level, it occurs at 
the local level, and it occurs at the national level. We have 
to try to find mechanisms that streamline these processes, that 
stabilize the rules of the game, that cut down on the 
litigation expense and that cut the risk, while at the same 
time protecting the environment and the other legitimate 
interests.
    But that remains a huge problem out there, and it 
discourages investment in infrastructure.
    Mr. Ose. I asked Mr. Carpenter this same question. In terms 
of the forward contracting tool for utilities, do you support 
different State's PUCs giving that to utilities?
    Mr. Kalt. Actually, I've written quite a bit on that and 
published a fair amount on that issue, and I think it's 
absolutely essential to an efficient natural gas system and 
ultimately the feeding of the gas to industrial users, the 
residential users and the power plants.
    Mr. Ose. Your analyses, have they included a discussion as 
to what percentage of a production portfolio should be exposed 
to the spot market?
    Mr. Kalt. Not in quite that way, and it's--let me give you 
a slightly different perspective. That's why Paul here has 
difficulty answering it in the generic.
    The way I look at that question is slightly differently. 
I've been a proponent of so-called incentive-based regulation 
which says, give the utility the flexibility to adjust to--if 
it sees softness in the spot market, go buy spot gas. If it 
thinks it's going to face a future where it needs to lock in 
prices, go get lock-term contracts or use other derivatives.
    But by using incentive-based regulation rather than a 
strict sort of rules like 23 percent of your portfolio should 
be spot, I think therein lies a better way to go about this 
question because, after all, you're trying to get people to 
adjust to the changes in their systems, the changes in the 
forecasts and so forth, and you've got to leave that 
flexibility within the system.
    Mr. Ose. So you give them a range, basically?
    Mr. Kalt. Or a range, or a range based on their 
performance, the rates of return and so forth.
    Mr. Ose. Mr. Amirault, same question. What should Congress 
be doing?
    Mr. Amirault. I agree with the other panelists----
    Mr. Ose. Of all the panelists, I have to tell you, these 
guys are a lot smarter than me, and Gay knows a lot more of the 
people, but you and I are business people, so, you know, you 
have a unique perspective here.
    Mr. Amirault. Thank you. The coordination of the issue is 
essential, and that is, hearings like this help with that, so 
that is important. It's not just an in-State problem; it's not 
just a problem coming up to the State borders. There's a 
regional supply/demand challenge here that has to be managed 
and coordinated.
    It's not good enough to simply look at the balance of 
pipeline capacity coming to the State's borders and coming away 
from the State border and see if that matched. That doesn't 
tell you if the situation is in hand or not. We have to look at 
the supply/demand balance across the region, because even if 
there is capacity coming to the border and the ability to take 
it away, just like depending on what customers do, there might 
not be gas in storage to meet peak demands.
    If customers didn't fill it, there might not be gas in the 
pipelines to serve the California market if they've decided to 
deliver that gas to a different market upstream. You've got to 
assess the whole balance, and that coordination is something 
that hearings like this can really help assist with.
    I'd also encourage, where you can, the State to complete 
the unbundling task. To the extent that they can push the SoCal 
system to look a little bit more like PG&E's. PG&E's isn't 
completely unbundled either, but it goes a lot further than 
SoCal's. If PG&E's gas transmission system comes under Federal 
jurisdiction, as proposed in their bankruptcy solution, then I 
would encourage FERC, and to the extent you can influence that, 
not to mess up what they've done. Just complete the job.
    Finally, I would encourage the development of incentives to 
promote efficiency on the interstate pipeline system. 
Efficiencies in their design and in their utilization.
    Mr. Ose. Could you be a little more specific on those 
efficiencies?
    Mr. Amirault. As I've discussed in my testimony, if a 
pipeline can be designed to move the average day load from the 
supply basin to a market area storage and then the peak day 
from storage on to the end-use customer, that's a lot less 
costly than moving the peak day supply all the way from the 
supply basin.
    Mr. Ose. Your point being that then you only have to 
capitalize the big pipe from the storage back into the 
distribution rather than from the source to the storage.
    Mr. Amirault. Exactly.
    Mr. Ose. OK.
    Ms. Friedmann.
    Ms. Friedmann. Well, first of all, I want to commend 
Congress, at least the House, for passing H.R. 4, because I 
think the first thing we need is, we need to continue to make 
sure we have a supply of natural gas, and that was one of the 
problems that faced the entire country last winter.
    Second, I do want to say then on the NIMBY problem, we can 
use the support of Congress individually--not as a body, but as 
individual Members--when interstate pipelines are applying to 
FERC, to support it. When you think that there is a market out 
there and you know that there's a market out there for us to 
help respond to some of the, ``Hell, no, we don't want to build 
in our backyard'' types of people.
    And I also would encourage, particularly the Californians, 
to look at encouraging the State to be more receptive to 
opening up their system and to permitting more interstate 
pipelines into California. I think you'll end up with a 
healthier economy.
    Mr. Ose. OK. We're going to go ahead and wrap up here. I 
want to advise everybody we're going to leave the record open 
for 10 days, during which time we hope to communicate such 
questions that we'll have to each of you in writing, such as 
the two that I asked the two of you in particular. The other 
Members of Congress will be able to submit some more questions, 
and they will be forwarded to the appropriate parties.
    I want to thank you all for coming, as well as the first 
panel. This is, to me, something that is very long-range, 
because as you look out over the coming 20 or 30 or 50 years, 
in California you see us going toward the fuel that has been 
very gentle, on a relative basis, to the environment. And I 
suspect that the rest of the country is going to have to go 
that way.
    Accordingly, the way we deal with that is we put in place 
now the policies that allow us to create the solutions 10, 15, 
20 years hence. And to the extent that you've participated 
today to help us learn what we need to do, you have Congress's 
appreciation, as well as the country's.
    This is not an easy task. There are lots of competing 
interests. There are clearly differences of opinion on some 
things. But the education that you impart to us will help us 
with our policy decisions, and we thank you for that.
    We are adjourned.
    [Whereupon, at 3:26 p.m., the subcommittee was adjourned.]
    [Additional information submitted for the hearing record 
follows:]
[GRAPHIC] [TIFF OMITTED] 82547.105

[GRAPHIC] [TIFF OMITTED] 82547.106

[GRAPHIC] [TIFF OMITTED] 82547.107

[GRAPHIC] [TIFF OMITTED] 82547.108

[GRAPHIC] [TIFF OMITTED] 82547.109

[GRAPHIC] [TIFF OMITTED] 82547.110

[GRAPHIC] [TIFF OMITTED] 82547.111

[GRAPHIC] [TIFF OMITTED] 82547.112

[GRAPHIC] [TIFF OMITTED] 82547.113

[GRAPHIC] [TIFF OMITTED] 82547.114

[GRAPHIC] [TIFF OMITTED] 82547.115

[GRAPHIC] [TIFF OMITTED] 82547.116

[GRAPHIC] [TIFF OMITTED] 82547.117

[GRAPHIC] [TIFF OMITTED] 82547.118

[GRAPHIC] [TIFF OMITTED] 82547.119

[GRAPHIC] [TIFF OMITTED] 82547.120

[GRAPHIC] [TIFF OMITTED] 82547.121

[GRAPHIC] [TIFF OMITTED] 82547.122

[GRAPHIC] [TIFF OMITTED] 82547.123

[GRAPHIC] [TIFF OMITTED] 82547.124

[GRAPHIC] [TIFF OMITTED] 82547.125

[GRAPHIC] [TIFF OMITTED] 82547.126

[GRAPHIC] [TIFF OMITTED] 82547.127

[GRAPHIC] [TIFF OMITTED] 82547.128

[GRAPHIC] [TIFF OMITTED] 82547.129

[GRAPHIC] [TIFF OMITTED] 82547.130

[GRAPHIC] [TIFF OMITTED] 82547.131

[GRAPHIC] [TIFF OMITTED] 82547.132

[GRAPHIC] [TIFF OMITTED] 82547.133

[GRAPHIC] [TIFF OMITTED] 82547.134

[GRAPHIC] [TIFF OMITTED] 82547.135

[GRAPHIC] [TIFF OMITTED] 82547.136

[GRAPHIC] [TIFF OMITTED] 82547.137

[GRAPHIC] [TIFF OMITTED] 82547.138

[GRAPHIC] [TIFF OMITTED] 82547.139

[GRAPHIC] [TIFF OMITTED] 82547.140

[GRAPHIC] [TIFF OMITTED] 82547.141

[GRAPHIC] [TIFF OMITTED] 82547.142

[GRAPHIC] [TIFF OMITTED] 82547.143

[GRAPHIC] [TIFF OMITTED] 82547.144

[GRAPHIC] [TIFF OMITTED] 82547.145

[GRAPHIC] [TIFF OMITTED] 82547.146

[GRAPHIC] [TIFF OMITTED] 82547.147

[GRAPHIC] [TIFF OMITTED] 82547.148

[GRAPHIC] [TIFF OMITTED] 82547.149

[GRAPHIC] [TIFF OMITTED] 82547.150

[GRAPHIC] [TIFF OMITTED] 82547.151

[GRAPHIC] [TIFF OMITTED] 82547.152

[GRAPHIC] [TIFF OMITTED] 82547.153

[GRAPHIC] [TIFF OMITTED] 82547.154

[GRAPHIC] [TIFF OMITTED] 82547.155

[GRAPHIC] [TIFF OMITTED] 82547.156

[GRAPHIC] [TIFF OMITTED] 82547.157

[GRAPHIC] [TIFF OMITTED] 82547.158

[GRAPHIC] [TIFF OMITTED] 82547.159

[GRAPHIC] [TIFF OMITTED] 82547.160

[GRAPHIC] [TIFF OMITTED] 82547.161

[GRAPHIC] [TIFF OMITTED] 82547.162

[GRAPHIC] [TIFF OMITTED] 82547.163

[GRAPHIC] [TIFF OMITTED] 82547.164

[GRAPHIC] [TIFF OMITTED] 82547.165

[GRAPHIC] [TIFF OMITTED] 82547.166

[GRAPHIC] [TIFF OMITTED] 82547.167

[GRAPHIC] [TIFF OMITTED] 82547.168

[GRAPHIC] [TIFF OMITTED] 82547.169

[GRAPHIC] [TIFF OMITTED] 82547.170

[GRAPHIC] [TIFF OMITTED] 82547.171

[GRAPHIC] [TIFF OMITTED] 82547.172

[GRAPHIC] [TIFF OMITTED] 82547.173

[GRAPHIC] [TIFF OMITTED] 82547.174

[GRAPHIC] [TIFF OMITTED] 82547.175

[GRAPHIC] [TIFF OMITTED] 82547.176

[GRAPHIC] [TIFF OMITTED] 82547.177

[GRAPHIC] [TIFF OMITTED] 82547.178

[GRAPHIC] [TIFF OMITTED] 82547.179

[GRAPHIC] [TIFF OMITTED] 82547.180

[GRAPHIC] [TIFF OMITTED] 82547.181

[GRAPHIC] [TIFF OMITTED] 82547.182

[GRAPHIC] [TIFF OMITTED] 82547.183

[GRAPHIC] [TIFF OMITTED] 82547.184

[GRAPHIC] [TIFF OMITTED] 82547.185

[GRAPHIC] [TIFF OMITTED] 82547.186

[GRAPHIC] [TIFF OMITTED] 82547.187

[GRAPHIC] [TIFF OMITTED] 82547.188

[GRAPHIC] [TIFF OMITTED] 82547.189

[GRAPHIC] [TIFF OMITTED] 82547.190

[GRAPHIC] [TIFF OMITTED] 82547.191

[GRAPHIC] [TIFF OMITTED] 82547.192

[GRAPHIC] [TIFF OMITTED] 82547.193

[GRAPHIC] [TIFF OMITTED] 82547.194

[GRAPHIC] [TIFF OMITTED] 82547.195

[GRAPHIC] [TIFF OMITTED] 82547.196

[GRAPHIC] [TIFF OMITTED] 82547.197

[GRAPHIC] [TIFF OMITTED] 82547.198

[GRAPHIC] [TIFF OMITTED] 82547.199

                                   - 
