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82–547 PDF 2002

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

(II)

COMMITTEE ON GOVERNMENT REFORM

DAN BURTON, Indiana, Chairman

BENJAMIN A. GILMAN, New York

CONSTANCE A. MORELLA, Maryland

CHRISTOPHER SHAYS, Connecticut

ILEANA ROS-LEHTINEN, Florida

JOHN M. MCHUGH, New York

STEPHEN HORN, California

JOHN L. MICA, Florida

THOMAS M. DAVIS, Virginia

MARK E. SOUDER, Indiana

STEVEN C. LATOURETTE, Ohio

BOB BARR, Georgia

DAN MILLER, Florida

DOUG OSE, California

RON LEWIS, Kentucky

JO ANN DAVIS, Virginia

TODD RUSSELL PLATTS, Pennsylvania

DAVE WELDON, Florida

CHRIS CANNON, Utah

ADAM H. PUTNAM, Florida

C.L. ‘‘BUTCH’’ OTTER, Idaho

EDWARD L. SCHROCK, Virginia

JOHN J. DUNCAN, JR., Tennessee

——— ———

HENRY A. WAXMAN, California

TOM LANTOS, California

MAJOR R. OWENS, New York

EDOLPHUS TOWNS, New York

PAUL E. KANJORSKI, Pennsylvania

PATSY T. MINK, Hawaii

CAROLYN B. MALONEY, New York

ELEANOR HOLMES NORTON, Washington,

DC

ELIJAH E. CUMMINGS, Maryland

DENNIS J. KUCINICH, Ohio

ROD R. BLAGOJEVICH, Illinois

DANNY K. DAVIS, Illinois

JOHN F. TIERNEY, Massachusetts

JIM TURNER, Texas

THOMAS H. ALLEN, Maine

JANICE D. SCHAKOWSKY, Illinois

WM. LACY CLAY, Missouri

DIANE E. WATSON, California

——— ———

———

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

CHRISTOPHER SHAYS, Connecticut

JOHN M. MCHUGH, New York

STEVEN C. LATOURETTE, OHIO

CHRIS CANNON, Utah

JOHN J. DUNCAN, JR., Tennessee

——— ———

JOHN F. TIERNEY, Massachusetts

TOM LANTOS, California

EDOLPHUS TOWNS, New York

PATSY T. MINK, Hawaii

DENNIS J. KUCINICH, Ohio

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

(III)

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

(1)

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:]

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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

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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:]

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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

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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:]

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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

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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 takeaway 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:]

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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

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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:]

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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-ofstate power plants will export power to California and are more efficient than the existing units served by the SoCalGas system, we

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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 takeaway 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:]

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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

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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

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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 commisVerDate 11-MAY-2000 10:49 Nov 07, 2002 Jkt 000000 PO 00000 Frm 00070 Fmt 6633 Sfmt 6633 C:\DOCS\82547.TXT HGOVREF1 PsN: HGOVREF1
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sioners 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.

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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:]

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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.

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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

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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

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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 31⁄2 cents. We set the price at 61⁄2 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 61⁄2 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

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sible. 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

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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.

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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

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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.

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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?

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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?

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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.

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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

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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.

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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

85

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

86

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.

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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

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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.]

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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 bilVerDate 11-MAY-2000 10:49 Nov 07, 2002 Jkt 000000 PO 00000 Frm 00093 Fmt 6633 Sfmt 6633 C:\DOCS\82547.TXT HGOVREF1 PsN: HGOVREF1
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lion 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

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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:]

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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

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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:]

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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

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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:]

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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.

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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:]

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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.

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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

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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.

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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 baVerDate 11-MAY-2000 10:49 Nov 07, 2002 Jkt 000000 PO 00000 Frm 00148 Fmt 6633 Sfmt 6633 C:\DOCS\82547.TXT HGOVREF1 PsN: HGOVREF1
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sins, 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.

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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

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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.

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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

149

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?

150

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

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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,

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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

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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.

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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.

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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.

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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?

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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?

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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.

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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.]

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