Ask the Scholar
Document scope · 1 page
Scholar
Ask about this object, its catalog metadata, its source description, or the page inventory.
For page-specific OCR and visual context, open one of the page chats.
Scholar Source Context
Document identity
localId
323153620
label
American Gas Assoc. Teleconference 10/28/91 [OA 8317] [1]
core
doc
dtoType
document
citationUrl
pageCount
1
Source metadata
id
323153620
contentType
document
title
American Gas Assoc. Teleconference 10/28/91 [OA 8317] [1]
citationUrl
identifierLocal
13778-004
collections
Records of the White House Office of Speechwriting (George H. W. Bush Administration)
Speech Backup Chronological Files
imageCount
1
hasImages
yes
source
import
hasTranscription
no
Source extras
naId
323153620
levelOfDescription
fileUnit
recordType
description
ocrSource
nara-archive
Single page context
seq
1
pageIndex
0
type
document
mediaId
d68c59042b30e1be
ocrText
Originally Processed With FOIA(s):
FOIA Number:
S; 2011-1613-F[1]
S
FOIA
MARKER
This is not a textual record. This is used as an
administrative marker by the George Bush Presidential
Library Staff.
Record Group/Collection:
George H.W. Bush Presidential Records
Collection/Office of Origin:
Speechwriting, White House Office of
Series:
Speech File Backup Files
Subseries:
Chron File, 1989-1993
OA/ID Number:
13778
Folder ID Number:
13778-004
Folder Title:
American Gas Assoc. Teleconference 10/28/91 [OA 8317] [1]
Stack:
Row:
Section:
Shelf:
Position:
G
26
21
7
3
THE WHITE HOUSE
WASHINGTON
AUGUST 5, 1991
MEMORANDUM FOR BARRY TRON, DIRECTOR, PUBLIC AFFAIRS
FROM:
JEFF VOGT Jm ASSOCIATE DIRECTOR, PUBLIC LIAISON
SUBJECT:
SATELLITE TELECONFERENCE FOR AMERICAN GAS
ASSOCIATION (AGA) CONFERENCE
Attached is a letter from AGA requesting a satellite
teleconference with the President for their annual conference in
San Diego, CA; October 27 - 30, 1991.
I strongly recommend this request be granted. The event allows a
forum for our National Energy Strategy. Moreover, AGA has been
extremely helpful with a number of issues on the Hill, including
the budget agreement, the Gulf vote, the capital gains fight and
clean air legislation. The conference is expected to exceed
1,500 in attendance.
Barry. Please let me know if you need additional information. Thanks,
CC: Bobbie Kilberg
Kathy Jeavons
Russ Keenewill call
by COB Fri. 10/18
(ul TPs, bckgrnd)
A&A
Association Gas Guillintrol POTUS
American
1515 Wilson Boulevard. Arlington. Va. 22209
Telephone (703) 841-3512
Michael Baly III
July 8, 1991
President
RESEARCH in Russ KEENE
Mr. Jeff Vogt
565-3138-806
Associate Director
Office of Public Liaison
The White House
Washington, D.C. 20500
Dear Jeff:
Pursuant to our discussion recently at the Spanish Ambassador's residence and your
discussions with Russ Keene of my staff, it is my pleasure to invite President Bush to
appear via teleconference hookup at A.G.A.'s American Gas Conference, scheduled for
October 27-30, 1991 at San Diego's Marriott Marina Hotel.
The American Gas Conference is the natural gas industry's largest general interest
meeting. We expect more than 1,000 delegates and 500 spouses and guests to attend
the meeting representing all levels of management from natural gas distribution and
pipeline companies, gas producers, gas appliance manufacturers, government, financial
organizations and other suppliers to our industry. The purpose of the conference is to
discuss the major issues that will affect the gas industry over the next decade.
We believe our many industry executives -- including a sizeable California contingent --
would greatly enjoy the opportunity to see and hear the President. Issues of interest
include the Administration's NES (which we strongly endorse), alternative fuel vehicle
development, environmental challenges and, of course, any other issue on the President's
mind that he would care to pass along to our group of industry leaders.
We look forward to working with you and others in the White House on a Presidential
teleconference to the American Gas Conference in October.
Thank you for your consideration in this matter.
Sincerely,
mike Baly
EDT 12:Noon Oct 20, 1990 MONDAY
Michael McCoRmiac Baly III
chan PULL
TECH: ROB QUINN
THE WHITE HOUSE
WASHINGTON
August 8, 1991
SCHEDULE PROPOSAL
TO:
KATHY SUPER
Deauty No istant to the President for
Appointments and Scheduling
THROUGH:
DORRANCE SMITH
Assistant to the President for Media Affairs
FROM:
BARRIE TRON
Director of Public Affairs
REQUEST:
Satellite toleconference for the American Cas
Association's American Gas Conference
PURPOSE:
To articulate the President's National Energy
Strategy, to an influential industry group.
BACKGROUND:
The American Gas Association (AGA) is holding
a major industry conference in San Diego in
which over 1,500 people are expected to
attend This group har been very supportive
of the President's National Energy Strategy
as well as other key initiatives including;
the budgets am eement, the Gulf vote, the
capital gains fight, and the clean air
legislation.
PREVIOUS
PART CIPATION:
None
DATE AND TIME:
October 27 - 30, 1991
DURATION: 20 minutes
LOCATION:
OEOB 459
PARTICIPANTS:
Dorrance Smith
Barrie Tron
WHCA personnel (2)
White house photogra pher
Interface Video Productions (3)
OUTLINE OF EVENT:
The Pre ident enters the Studio, participates
in the satellite teleconference, then
departs
REMARKS REQUIRED:
Brief remarks to be provided by the Office of
Communications
MEDIA COVERAGE:
Closed press
CARD
Bobbic Kilberg
sociation
(Jeff Vogi Vont 2 A.
X
S aregy
C
** The the
the ( $
IT ET
the
THE
If
-
THE
T
it the
FACT-CHECK COPY FACT- CHECK COPY
Grant / Aarhus
A:AGA Draft two
October 22, 1991
BRIEF REMARKS: AMERICAN GAS ASSOCIATION TELECONFERENCE
MONDAY, OCTOBER 28, 1991
10
A.M.
NOON
Chairman BillMcormick Farman
Ch.-Elect Dick
Thank you, Mike [Baly, President of AGA]. I'm glad to be
able to join you by satellite in San Diego at the 73rd Annual
Conference of the American Gas Association. I understand you'll
Russ
be hearing shortly from X Gregg Petersmeyer, one of my top
X
X
assistants and an "energy" expert himself -- he's a specialist on
channeling the tremendous energy of volunteers in our society.
I'd like to talk to you today about America's energy future
-- the indispensible foundation for the goods we produce, the
enterprises we launch and the lifestyles we enjoy. When this
Administration developed our National Energy Strategy, three
principles guided our policy-making: reducing our dependence on
foreign oil; protecting our environment; and promoting economic
growth. As a part of our comprehensive energy strategy, natural
gas is key to all three.
First, decreasing our dependence on foreign energy is a top
priority of this Administration. We're willing to practice what
PresDoc
we preach: in April of this year, I took action to put the
PresDoc
federal government in the lead on reducing our import dependence
p.456
p.456.452
X
by issuing an Executive Order that called for sharp reductions in
federal energy use. Under this new mandate, overall energy
consumption will be reduced by 20 percent from 1985 levels within
2
presi p.ust doc,
XX a decade, and automotive fuel consumption will XXXXX be pared by 20
federal
X.
X
10
Pres
Doc
X
cont.
percent from current levels within X four years.
Unlike other energy types, there are abundant supplies of
Ruth
natural gas within our borders -- in fact, the e Departme Department of
x
Marty Allda
586 3908
113/
586-6210 Bums
Energy recently reported a 111 percent replacement of reserves
DOE
(EIA)
for XYYX 1990 in the lower 48 states. And to guarantee that domestic
X
egy to
supplies of natural gas remain steady, we want to rely on the
logic of the marketplace. For example, in XXT 1989 we enacted XX a law
DOE
Marty Marday
phasing out the last federal wellhead price controls + on + natural X
XXXX
+
gas -- so that the free market could do its work.
Second, we are committed to preserving and protecting the
DOC
environment. Again, in 1990, we looked to the ingenuity of the
PresDoc
pres
velau
free market as we worked to defend our precious environment
through enactment of the Clean Air Act Amendments. The XXXX A.G.A.
AGA
was XXXX one of the first major trade groups to endorse our
Administrationsproposal for clean air legislation. I thank you
for that effort. As X clean-burning natural gas is put to work in
increasing amounts for generating electricity, for fueling
AGAL
vehicles, for natural gas cooling in the summer -- Americans know
the environment stands to benefit.
And third, energy security and environmental protection
must go hand in hand with economic growth. That growth directly
depends upon opening new markets and new opportunities for
American industry. A North American Free Trade Agreement will
promote economic growth throughout this continent. Your industry
knows what I'm talking about: already, the northern tier of
3
/
Mexico is the largest single export market for U.S. natural gas
with some 200 million cubic feet flowing across the border each
AGAI
day. Next year, it is expected that the flow will increase to
DOE
nearly 250 million cubic feet per day, and planned pipeline
expansions could triple the export levéls.
Economic growth also depends upon an educated workforce.
America's natural gas producers, companies and utilities are
doing a great deal to make their communities places where
learning can happen. X Your X "Education X 2000" X program X a XTen
due. brockwere AGA 2000
year X industry-wide X commitment toX helping our X nation X reform X its X
X
schools -- is XX a great example X of X the partnerships necessary to X
X
X
X
invent a new generation of American schools. I urge you and your
members to continue to pursue excellence in education so that we
can prepare American children to compete -- and win -- in the
global marketplace.
Economic growth, environmental conservation, energy
security, and a well-prepared workforce -- all are crucial to
America's success in the next century. As part of the fabric of
daily life in America -- your companies and employees can make a
difference. In many ways, you already are -- and for that, I
thank you.
I wish you a successful conference and best wishes in the
coming year. And now I'll take a few questions.
# # #
Mike Baly: Mr. President, our chairman Bill McCormick has a
question for you.
4
Bill McCormick: Mr. President, we praise you for your leadership
in the Clean Air Act Amendments passed by the Congress last year
and we were pleased to support the Administration's goals and the
Act. We appreciate your Administration's work toward enactment
of the National Energy Strategy that you proposed earlier this
year. A.G.A. also has been supportive of this initiative since
the outset. The Senate looks like it will begin debate soon on
the NES. How do you foresee the debate shaping and your
Administration's role as the debate unfolds?
ANSWER: Bill, as I said earlier, securing a clean and affordable
energy future is a very important objective of this
Administration. That is why I am supporting S. 1220, the
thatas
bipartisan energy bill now being considered by the Senate. This
bill incorporates many important principles of our National
Energy Strategy.
During the Senate's deliberations on this bill, we will be
working very closely with Senators Johnston and Wallop X to ensure
that our key provisions remain intact. For example, many X
Sen.
Egy
components XX of the bill, such XX as further deregulation of natural
comm.
gas, will increase domestic energy production and energy
efficiency. We need your industry's help in getting a good bill
on my desk -- we are expecting a few tough votes -- but I am
confident that the American people will understand the importance
of enacting a comprehensive, balanced energy bill.
Mike Baly: Mr. President, our Chairman-elect, Dick Farman, has a
question.
Dick Farman: Mr. President, in your remarks you mentioned
A.G.A.'s Education 2000 program and we are all looking forward to
hearing later in today's meeting from Gregg Petersmeyer on your
Administration's national service efforts. Would you care to
comment on other domestic initiatives that your Administration is
currently working on or has plans to introduce in the next year?
5
ANSWER: Dick, we've advanced a broad, aggressive domestic agenda
over the last two years -- one which has included such
legislative successes as the Clean Air Act Amendments, the
HUDPAI
Americans with Disabilities Act, our Child Care bill, and our
ownership
HOPE bill that promotes tenant management of public housing.
708 Jackie 0120 conn
Looking ahead, we've already mentioned our America 2000
education initiative and our National Energy Strategy, and
Congress is right now considering provisions of the
Administration's tough crime bill -- a bill that we sent to the
Marianne
brinex
Congress two years in a row before we saw any action on it. You
may remember that I challenged the Congress to complete action on
just two bills -- that crime bill and our transportation bill --
in 100 days. But here we are, eight months X later, still waiting
for both.
almost
We've also proposed a civil rights bill that will toughen
our civil rights laws without resorting to unfair quotas. Just
X
last week I signed an Executive Order to enact reforms in our
civil justice system, and we 11 be sending legislation to the
Congress on that very soon.
But most importantly, we've offered numerous economic reform
proposals which, if enacted by the Congress, would have long ago
X
promoted the economic growth that America needs. We've proposed a
capital gains tax cut to create more jobs, more federal funds for
research and development, enterprise zones to stimulate our
hardest-hit urban areas, and incentives for increased savings and
investment. Throughout the coming legislative year, we will
6
X X + + + + + + + +
fight tooth and nail for economic growth, opportunity and jobs.
I realize that's only a thumbnail sketch of our agenda, but I
hope I've answered your question. Once again, thanks for the
opportunity to join you today. Over and out.
# # #
Teleconference for the
10-28-91
American Gas Association's
Conference
Contacts: Paul Cuthringer x 2483
Maggie Minouge X 7150
gas is part of comprehensive strat
Grant / Aarhus
A:AGA Draft one
October 21, 1991
BRIEF REMARKS: AMERICAN GAS ASSOCIATION TELECONFERENCE
MONDAY, OCTOBER 28, 1991
10 A.M.
Thank you, Mike [Baly, President of AGA]. I'm glad to be
able to join you by satellite in San Diego at the 73rd Annual
Conference of the American Gas Association. I understand you'll
be hearing shortly from Gregg Petersmeyer, one of my top
assistants and an "energy" expert himself -- he's a specialist on
channeling the tremendous energy of volunteers in our society [Yuk Yuk
I'd like to talk to you today about America's energy future
-- the indispensible foundation for the goods we produce, the
enterprises we launch and the lifestyles we enjoy. When this
Administration developed our National Energy Strategy, three
The
good
principles guided our policy-making: ensuring America's energy
security; protecting our environment; and promoting economic
growth. Natural gas is vital to all three.
senter.
can wally hope to
Secreasing
First, Tessening our dependence on foreign
oil is a top
priority of this Administration. We're willing to practice what
we preach: in April of this year, I took action to put the
federal government in the lead on reducing our import dependence
by issuing an Executive Oreder that called for sharp reductions
in federal energy use. Under this new mandate, overall energy
consumption will be reduced by 20 percent from 1985 levels within
a decade, and automotive fuel consumption will be pared by 20
percent from current levels within four years.
2
Unlike other energy types, there are abundant supplies of
natural gas within our borders -- in fact, the Department of
what
does
then
Energy recently reported
a
111 percent replacement
of reserves
pean
for 1990 in the lower 48 states. And to guarantee that supplies
of natural gas remain steady, we want to rely on the logic of the
marketplace. For example, in 1989 we enacted a law phasing out
the last federal wellhead price controls on natural gas -- so
that the free market could do its work.
Secondl
our commitment teb to preserving and protecting the
environmentie unwavering. Again, in 1990, we looked to the
ingenuity of the free market as we worked to defend our precious
environment through enactment of the Clean Air Act Amendments.
The A.G.A. was one of the first major trade groups to endorse our
Administration proposal for clean air legislation. I thank you
for that effort. Americans know the environment stands to benefit
as clean-burning natural gas is put to work in increasing amounts
for generating electricity, for fueling vehicles, for natural gas
cooling in the summer, and in many other applications.
And third1 y energy security and environmental protection
must go hand in hand with economic growth. That growth directly
depends upon opening new markets and new opportunities for
American industry. A North American Free Trade Agreement will
promote economic growth throughout this continent. Your industry
knows what I'm talking about: already, the northern tier of
Mexico is the largest single export market for U.S. natural gas
with some 200 million cubic feet flowing across the border each
3
day. Next year, it is expected that the flow will increase to
nearly 250 million cubic feet per day, and planned pipeline
expansions could triple the export levels.
Economic growth also depends upon an educated workforce.
America's natural gas producers, companies and utilities are
doing a great deal to make their communities places where
learning can happen. Your "Education 2000" program -- a ten-
year, industry-wide commitment to helping our nation reform its
schools -- is a great example of the partnerships necessary to
invent a new generation of American schools. I urge you and your
members to continue to pursue excellence in education so that we
can prepare American children to compete -- and win -- in the
global marketplace.
Economic growth, environmental conservation, energy
security, and a well-prepared workforce are all crucial to
success
^
America's place in the next. century. Where that place is --
where we stand in the international arena -- is up to the
American people. As part of the fabric of daily life in America
-- your companies and employees can make a difference. In many
ways, you already are -- and for that, I thank you.
I wish you a successful conference and best wishes in the
coming year. And now I'll take a few questions.
# # #
[Two questions to come]
INTRODUCTION OF PRESIDENT GEORGE BUSH BY MIKE BALY
1991 AMERICAN GAS CONFERENCE
SAN DIEGO, CALIFORNIA
OCTOBER 28, 1991
GOOD MORNING, MR. PRESIDENT, I JOIN THE OVER 1,000 OF YOUR FELLOW
AMERICANS AND SUPPORTERS WHO APPRECIATE YOUR SPEAKING TO US TODAY.
THE AMERICAN GAS ASSOCIATION IS GRATEFUL FOR YOUR ADMINISTRATION'S
INCREASING FOCUS ON NATURAL GAS'S CONTRIBUTION TO OUR GREAT NATION.
AS YOU KNOW, WE HAVE BEEN AGGRESSIVELY WORKING TOWARD ENACTMENT
OF YOUR NATIONAL ENERGY STRATEGY.
MEMBERS AND FRIENDS OF THE AMERICAN GAS ASSOCIATION, IT IS AN HONOR
AND A PRIVILEGE FOR ME TO PRESENT TO YOU A GREAT FRIEND FOR MANY
YEARS OF THE AMERICAN GAS ASSOCIATION, THE PRESIDENT OF THE UNITED
STATES.
AGACONTACT: Russ Keene
703-841-8595
SUGGESTED REMARKS FOR PRESIDENT GEORGE BUSH
1991 AMERICAN GAS CONFERENCE
SAN DIEGO, CALIFORNIA
OCTOBER 28, 1991, 12:00 P.M. E.S.T.
THANK YOU, MIKE. AND CONGRATULATIONS ON A SUCCESSFUL FIRST YEAR AS
PRESIDENT OF THE AMERICAN GAS ASSOCIATION.
I WISH YOU ALL WELL ON THE 73RD ANNUAL CONFERENCE OF THE AMERICAN
GAS ASSOCIATION.
AS A VETERAN OF THE NATURAL GAS AND OIL BUSINESS, I FEEL A SPECIAL
KINSHIP WITH YOU GATHERED IN SAN DIEGO. I REGRET THAT I CANNOT BE WITH
YOU IN PERSON, BUT I AM PLEASED THAT GREGG PETERSMEYER OF OUR STAFF
IS WITH YOU TODAY.
AMERICA'S ENERGY INDUSTRY IS THE INDISPENSABLE FOUNDATION TO THE
GOODS WE PRODUCE, THE ENTERPRISES WE LAUNCH AND THE LIFESTYLES WE
ENJOY. THE NATURAL GAS INDUSTRY IS JUST ONE PART OF OUR NATION'S
ENERGY SECTOR. BUT THESE DAYS IT'S A PARTICULARLY EXCITING PART. THAT
IS BECAUSE ENERGY SECURITY, A CLEAN ENVIRONMENT AND A COMPETITIVE
ECONOMY ARE ALL HIGH ON THE LIST OF PUBLIC CONCERNS, AND THE USE OF
NATURAL GAS HELPS AMERICANS TO ACHIEVE ALL THREE OF THESE GOALS.
1
NATURAL GAS HELPS OUR ENERGY SECURITY BECAUSE THERE ARE ABUNDANT
SUPPLIES OF IT WITHIN OUR BORDERS. OUR DEPARTMENT OF ENERGY
REPORTED RECENTLY A 111% REPLACEMENT OF RESERVES FOR 1990 IN THE
LOWER 48 STATES. THAT'S AN IMPRESSIVE FEAT FOR A FUEL THAT SOME
PEOPLE ONCE COUNTED OUT AS A DISAPPEARING RESOURCE. CLEARLY, THE
PROBLEM BACK THEN WAS NOT A SCARCITY OF NATURAL GAS, BUT A SHORTAGE
OF COMMON SENSE IN THE HALLS OF GOVERNMENT. TODAY, JUST AS THERE IS
A NEW UNDERSTANDING OF FREE MARKETS AROUND THE WORLD, THERE IS WIDE
AGREEMENT ACROSS THE POLITICAL SPECTRUM THAT A FREE MARKET IS THE
BEST WAY TO ENSURE STEADY SUPPLIES OF NATURAL GAS. AND I AM PROUD
THAT UNDER MY ADMINISTRATION IN 1989 WE ENACTED A LAW PHASING OUT THE
LAST FEDERAL WELLHEAD PRICE CONTROLS ON NATURAL GAS SO THAT THE
MARKET CAN DO ITS WORK.
MY ADMINISTRATION LOOKS FORWARD TO
WORKING WITH YOU TO INCREASE THE DEMAND FOR NATURAL GAS, SO THAT WE
No
CAN PROVIDE FOR NOT ONLY A STRONG DRILLING INFRASTRUCTURE IN OUR
(?)
COUNTRY BUT A STRONG DISTRIBUTION AND TRANSMISSION SYSTEM ALSO.
NATURAL GAS IS ALSO IMPORTANT FOR OUR COUNTRY'S ENVIRONMENT. IN
ENACTING THE CLEAN AIR ACT AMENDMENTS OF 1990, OUR GOVERNMENT
ENSURED THAT AMERICANS WILL ENJOY CLEANER AIR, AND WE DID SO IN A WAY
THAT EMPOWERS THE FORCES OF THE MARKETPLACE RATHER THAN
ENCUMBERING THEM.
2
A.G.A. WAS ONE OF THE FIRST MAJOR TRADE GROUPS TO ENDORSE OUR
ADMINISTRATION PROPOSAL FOR THAT LEGISLATION. I THANK YOU FOR THAT
EFFORT, AND I KNOW THE NATION WILL BENEFIT AS CLEAN BURNING NATURAL
GAS IS PUT TO WORK IN INCREASING AMOUNTS FOR GENERATING ELECTRICITY,
FOR FUELING VEHICLES, FOR NATURAL GAS COOLING IN THE SUMMER AND IN
MANY OTHER APPLICATIONS.
I
NATURAL GAS IS A VERY ECONOMICAL FUEL. UNLIKE OIL, THE VAST MAJORITY
OF THE GAS WE USE IS PRODUCED HERE IN THIS COUNTRY, AND ALMOST ALL OF
IT IN THIS CONTINENT. AND, AS MUCH AS I FAVOR DEVELOPING OUR DOMESTIC
OIL INDUSTRY TO THE FULLEST, NATURAL GAS IS SIGNIFICANTLY CHEAPER THAN
OIL ON AN ENERGY EQUIVALENT BASIS.
THAT'S WHY WHEN MY
ADMINISTRATION'S BALANCED NATIONAL ENERGY STRATEGY PROPOSAL WAS
INTRODUCED IN FEBRUARY, WE SAID THAT MAKING A CHOICE TO INCREASE OUR
USE OF NATURAL GAS COULD "BOOST THE GROSS NATIONAL PRODUCT, REDUCE
OIL IMPORTS, AND IMPROVE THE NATION'S TRADE BALANCE."
AS YOU KNOW, MANY OF THE PROVISIONS FOR OUR NATIONAL ENERGY STRATEGY
OUR NOW EMBODIED IN LEGISLATION BEING CONSIDERED BY THE CONGRESS
AND I APPRECIATE VERY MUCH, MIKE, AND CHAIRMAN BILL MCCORMICK WHAT
A.G.A. IS DOING IN ACTIVELY SUPPORTING THIS LEGISLATION.
TODAY, I CAN THINK OF NO MORE IMPORTANT CHOICE THAT AMERICANS CAN
MAKE THAN TO GIVE THE NATIONAL ENERGY SECURITY ACT A VIGOROUS
3
BACKING. FOR THREE MORE DAYS IT WILL BE NATIONAL ENERGY AWARENESS
MONTH. THERE IS NO BETTER TIME TO REMIND YOUR SENATORS AND
CONGRESSMEN HOW VITAL IT IS THAT WE BEGIN TO PUT IN PLACE A NATIONAL
ENERGY STRATEGY TO BEST UTILIZE ALL OF OUR NATION'S ENERGY RESOURCES.
ANOTHER PART OF THE STRATEGY IS TO ENSURE A FAIR AND EXPEDITIOUS
REGULATORY SYSTEM FOR INTERSTATE PIPELINES. YOUR INDUSTRY HAS SEEN
DRAMATIC CHANGE IN RECENT YEARS AS THE FEDERAL ENERGY REGULATORY
COMMISSION HAS USHERED IN THE ERA OF "OPEN ACCESS" TRANSMISSION.
I
HOPE THAT YOU AGREE WITH ME THAT MARTIN ALLDAY IS DOING A FINE JOB AS
FERC CHAIRMAN AND I APPRECIATE A.G.A.'S CLOSE WORKING RELATIONSHIP WITH
HIM.
I KNOW YOU ARE WORKING WITH MARTIN ON SOME CHANGES TO THE RECENT
X
RULEMAKING AT FERC AND WE HOPE THAT WE CAN BE RESPONSIVE TO YOUR
CONCERNS ON THIS.
SPEAKING TO YOU IN SOUTHERN CALIFORNIA, I CAN'T FAIL TO MENTION AN
EXCITING NEW TECHNOLOGY THAT PROMISES TO HELP OUR NATION RESPOND TO
BOTH THE CLEAN AIR ACT AND THE NATIONAL ENERGY STRATEGY. I MEAN
NATURAL GAS VEHICLES.
SOUTHERN CALIFORNIA HAS TAKEN A LEAD IN LOOKING AT ALTERNATIVES TO
TRADITIONAL GASOLINE AND DIESEL FUELS. I KNOW YOUR INCOMING CHAIRMAN
4
DICK FARMAN AND HIS COMPANY, SOUTHERN CALIFORNIA GAS CO., HAVE BEEN
ACTIVE IN THE NATURAL GAS VEHICLE FIELD. SO HAVE MANY OTHERS AROUND
THE COUNTRY. THE FEDERAL GOVERNMENT OPERATES OVER 200,000 CIVILIAN
STYLE VEHICLES AND PURCHASES AROUND 50,000 EACH YEAR. EQUIPPING AS
MANY AS POSSIBLE TO BURN ALTERNATIVE FUELS CAN HELP TO ESTABLISH A
MARKET FOR SUCH VEHICLES, AND DEMONSTRATE THEIR FEASIBILITY TO THE
PRIVATE SECTOR. OUR ADMINISTRATION IS WORKING TO CONVERT OUR OWN
GOVERNMENT VEHICLES, AS YOU'VE SEEN IN THE DEPARTMENT OF ENERGY AND
NOW THE DEPARTMENT OF NAVY, THE POSTAL SERVICE -- AND THERE WILL BE
OTHERS AS WELL.
TODAY, FEDERAL AGENCIES USE OVER 480,000 BARRELS OF PETROLEUM
PRODUCTS EACH DAY. THAT NUMBER INCLUDES OVER 5.8 MILLION GALLONS OF
FUEL OIL, AND 3.6 MILLION GALLONS OF GASOLINE. WE CAN DO BETTER. WE
MUST DO BETTER. WE WILL DO BETTER. INDEED, THE FEDERAL GOVERNMENT
NEEDS TO LEAD THE WAY IN SHOWING HOW WE CAN CUT OUR OIL IMPORT
DEPENDENCE, AND ASSURE AMERICA'S ENERGY SECURITY.
ON APRIL 17TH, 1991, I TOOK ACTION TO PUT THE FEDERAL GOVERNMENT IN THE
LEAD ON REDUCING OUR IMPORT DEPENDENCE BY ISSUING AN EXECUTIVE
ORDER THAT CALLED FOR SHARP REDUCTIONS IN FEDERAL ENERGY USE. UNDER
THIS NEW MANDATE, OVERALL ENERGY CONSUMPTION WILL BE REDUCED BY 20
PERCENT FROM 1985 LEVELS WITHIN A DECADE, AND AUTOMOTIVE FUEL
CONSUMPTION WILL BE PARED BY 10 PERCENT FROM CURRENT LEVELS WITHIN
5
FOUR YEARS.
I KNOW THAT YOUR BOARD OF DIRECTORS YESTERDAY DISCUSSED INCREASING
SHORT-TERM DEMAND FOR NATURAL GAS WHICH INCLUDED URGING OUR
GOVERNMENT TO LOOK AT REDUCING OIL IN 80,000 OF OUR GOVERNMENT'S
FEDERAL INSTALLATIONS. PLEASE BE ASSURED THAT WE ARE TAKING YOUR
ADVICE AND COUNSEL UNDER CONSIDERATION AND WILL BE IN TOUCH WITH YOU
ON THIS SOON.
OUR WORK ON A NORTH AMERICAN FREE TRADE AGREEMENT HOLDS FORTH THE
PROMISE OF UNFETTERING COMMERCE IN ENERGY THROUGHOUT THE
CONTINENT. WE HAVE ALREADY SEEN HOW IMPORTANT THIS TRADE CAN BE.
TODAY, THE NORTHERN TIER OF MEXICO IS THE LARGEST SINGLE EXPORT
MARKET FOR U.S. NATURAL GAS WITH SOME 200 MILLION CUBIC FEET FLOWING
ACROSS THE BORDER EACH DAY. NEXT YEAR IT IS EXPECTED THAT THE FLOW
WILL INCREASE TO FROM 225 TO 250 MILLION CUBIC FEET PER DAY, AND PLANNED
PIPELINE EXPANSIONS COULD RAISE THAT FIGURE TO 750 MILLION CUBIC FEET
PER DAY. I APPRECIATE THE SUPPORTIVE LETTER A.G.A. SENT TO AMBASSADOR
HILLS, OUR U.S. TRADE REPRESENTATIVE, WHICH POINTED OUT THE NEED TO
COVER ENERGY IN THE NEGOTIATIONS TO ELIMINATE BARRIERS FOR TRADE IN
NORTH AMERICA.
FINALLY, I COMMEND YOU ON YOUR "EDUCATION 2000" PROGRAM - -- A 10-YEAR,
INDUSTRY WIDE COMMITMENT TO HELPING OUR NATION REFORM ITS SCHOOLS
6
TO MEET THE 6 NATIONAL GOALS AGREED UPON BY ME AND THE NATION'S
GOVERNORS AT THE ENERGY SUMMIT SEVERAL YEARS AGO.
AMERICA'S NATURAL GAS COMPANIES, NATURAL GAS UTILITIES AND PIPELINES
AND PRODUCERS ALREADY DO A GREAT DEAL IN THEIR COMMUNITIES AND
SERVICE AREAS TO ADVANCE THE CAUSE OF U.S. EDUCATION. UNDER THE
BANNER OF "EDUCATION 2000," WITH A.G.A. ACTING AS A CLEARINGHOUSE FOR
IDEAS, YOU WILL BE DOING MORE IN THE YEARS TO COME. AND I WELCOME
THAT, BECAUSE IT IS IMPERATIVE THAT, THROUGH OUR ADMINISTRATION'S
AMERICA 2000 PROGRAM, ALONG WITH YOUR PROGRAM AND OTHERS, THAT WE
REFORM THE EDUCATIONAL SYSTEM SO THAT IT CAN PREPARE AMERICAN
CHILDREN TO COMPETE EFFECTIVELY IN THE WORLD ECONOMY.
I AM PLEASED THAT GREGG PETERSMEYER, ONE OF MY SENIOR ASSISTANTS AND
DIRECTOR OF NATIONAL SERVICE, WILL BE SPEAKING TO YOU TODAY. HIS OFFICE
OVERSEES OUR "POINTS OF LIGHT" PROGRAM WHICH SEEKS TO CHANNEL THE
ENORMOUS ENERGIES OF VOLUNTEERISM IN OUR SOCIETY. WHEN WE VISUALIZE
A THOUSAND POINTS OF LIGHT, SOME OF THESE LIGHTS ARE GAS LIGHTS.
- THAT'S WHY I PARTICULARLY COMMEND YOUR INCOMING CHAIRMAN DICK
FARMAN ON HIS NEW THEME, OF "AMERICA'S NATURAL GAS INDUSTRY: WORKING
TOGETHER TO MARKET THE FUEL OF CHOICE" BECAUSE INDUSTRY UNITY WILL
BE VERY IMPORTANT TO MARKET THE BENEFITS OF NATURAL GAS IN OUR
COUNTRY. I BELIEVE THAT THE ROLE OF THE AMERICAN GAS ASSOCIATION IS
7
CRITICAL IN HELPING BRING ALL THE SEGMENTS OF OUR INDUSTRY TOGETHER -
- THE PRODUCERS, PIPELINES AND UTILITIES -- TO WORK TOWARD THE NATIONAL
GOALS WHICH I HAVE CITED.
IN CLOSING, LET ME ASSURE YOU THAT MY ADMINISTRATION SEES NATURAL GAS
AS A VERSATILE ENERGY RESOURCE OF GROWING IMPORTANCE FOR AMERICA
INTO THE 21ST CENTURY. WHEN CHOICES ARE MADE ABOUT ENERGY, NATURAL
GAS IS A VERY WISE CHOICE.
I WISH YOU A SUCCESSFUL CONFERENCE, THANK YOU FOR INVITING ME TO
PARTICIPATE. NOW I'LL BE HAPPY TO TAKE A COUPLE OF QUESTIONS.
# # # # #
Proposed Q &A
MIKE BALY:
MR. PRESIDENT, OUR CHAIRMAN BILL MCCORMICK HAS A QUESTION FOR YOU.
BILL MCCORMICK:
MR. PRESIDENT, AT SOME TIME IN THE NEAR FUTURE WE'D LIKE TO INTRODUCE
TO YOU THE QUALITY BENEFITS OF THE FIRST MASS-PRODUCED ALL NATURAL
GAS PICK-UP TRUCK MANUFACTURED BY GMC TRUCK. OUR INDUSTRY HOPES TO
SELL 5-8,000 OF THESE VEHICLES TO DEMONSTRATE THEIR ABILITY TO
CONTRIBUTE TO IMPROVING AIR QUALITY AS YOU TOUCHED UPON IN YOUR
8
REMARKS. MAY I CORDIALLY INVITE YOU TO TAKE A SPIN IN AN NGV, MR.
PRESIDENT. IT COULD BE ARRANGED ALMOST ANY TIME SINCE ONE OF THE
NATION'S MORE THAN 350 NATURAL GAS VEHICLE FUELING STATIONS IS NOW
OPEN JUST DOWN THE STREET FROM THE WHITE HOUSE.
BUSH ANSWER:
BILL, I HAVE BEEN IN A DUAL-FUEL NATURAL GAS VEHICLE AND I REMEMBER IT
LOOKED JUST LIKE A REGULAR CAR, RODE JUST LIKE A REGULAR CAR, BUT THE
ONLY DIFFERNCE WAS IT DID NOT POLLUTE LIKE A REGULAR CAR! AND, BILL, I
WOULD LIKE TO COMPLIMENT YOU ON YOUR LEADERSHIP IN REPRESENTING THE
GAS INDUSTRY IN MANY MEETINGS WITH THE BIG THREE AUTO MAKERS WHICH
BROUGHT ABOUT THE DEVELOPMENT OF THESE PROMOSING NEW VEHICLES. AS
VICE PRESIDENT, I SERVED AS CHAIRMAN OF THE WHITE HOUSE COMMISSION ON
REGULATORY REFORM. IN THAT CAPACITY I BECAME FAMILIAR WITH THE
ADVANTAGES OF ALTERNATIVE FUELS AND THE IMPORTANT ROLE THAT
COMPRESSED NATURAL GAS CAN PLAY. AT THAT TIME I CALLED NATURAL GAS
OUR NATION'S "ACE IN THE HOLE." -- AND I BELIEVE THAT EVEN MORE STRONGLY
TODAY. I LOOK FORWARD TO RIDING IN THAT NEW ALL NATURAL GAS PICK-UP
TRUCK SOON, JUST LIKE WE USE DOWN IN TEXAS.
MIKE BALY:
MR. PRESIDENT, OUR CHAIRMAN-ELECT, DICK FARMAN, HAS A QUESTION FOR
YOU.
9
DICK FARMAN:
MR. PRESIDENT, TODAY ABOUT 7 PERCENT OF FEDERAL ENERGY RESEARCH-AND-
DEVELOPMENT DOLLARS ARE TARGETED TO NATURAL GAS PRODUCTION AND USE
TECHNOLOGIES, THOUGH NATURAL GAS ACCOUNTS FOR 24 PERCENT OF THE
NATION'S ENERGY USE.
I VERY MUCH APPRECIATE HENSON MOORE'S
WILLINGNESS TO DISCUSS THIS IMPORTANT MATTER WITH ME ON SEVERAL
OCCAISIONS. DO YOU FORESEE THAT NATURAL GAS WILL RECEIVE INCREASED
FEDERAL R&D FUNDING?
BUSH ANSWER:
DICK, OUR NES PRINCIPLES INCLUDE EMPHASIS ON R&D INITIATIVES AS WELL AS
ENHANCING OUR NATION'S ENVIRONMENTAL QUALITY AND REDUCING OUR
DEPENDENCE ON IMPORTED OIL. NATURAL GAS FITS VERY WELL WITHIN THESE
PRINCIPLES.
SO, I FULLY EXPECT THAT YOU WILL SEE MY BUDGET
RECOMMENDATIONS FOR INCREASES IN NATURAL GAS R&D.
10
THE WHITE HOUSE
WASHINGTON
DOE reported
AGA 111% replacement
of reserves
figure
for 1990
- how does it got
replaced?
703-841-8400
Russ Keenel
egg EIA dmin. # DOE agency study from 2mos.
ey to average "fo of 30 top of
producing companies (Exxon, Mobil,
etc)
how much gas did
you sell? how much
gas did you find to sintle
ground.
discovered
replace what you sold.
A&A
American Gas
1515 Wilson Boulevard, Arlington, Va. 22209
Association
Telephone (703) 841-8612
Michael Baly III
President
October 17, 1991
Hon. Carla A. Hills
United States Trade Representative
600 17th Street, N.W.
Washington, DC 20506
Dear Ambassador Hills:
The natural gas industry would like to take this opportunity to commend you and your
staff on the progress made toward developing a North American Free Trade Agreement.
Our industry supports the Administration in its effort of eliminating barriers for trade, and
would like to ensure that energy, including natural gas, issues continue to be covered in
your negotiation.
At the present time, the U.S. natural gas industry is poised to export increasing volumes
of natural gas to Mexico. However, in order to maximize cross-border energy trade, we
need to develop the transmission and distribution systems needed in Mexico to deliver
the gas, as well as end-uses for that gas, such as gas-fired electric power generation.
The ability to develop the energy infrastructure in Mexico is an important trade opportunity
for U.S. energy companies. Our companies have expertise both in the design and
construction of natural gas delivery systems and gas-fired electric generating stations.
If we can be of assistance to your office on these issues please do not hesitate to call
upon us. Lorraine Cross, our director of State and Executive Branch Relations and Tom
Saunders, our manager of Federal Financial Relations from Energen Corp. of Birmingham,
Alabama are at your service.
Sincerely,
michael Baly III
Michael Baly III
A&A
American Gas
Association
Planning & Analysis
Issues
Issue Brief 1991 - 8
July 3, 1991
1991 MID-YEAR GAS DEMAND OUTLOOK
Natural gas consumption was up slightly in the first quarter of 1991. After levelling off in 1990 due
to warm weather, preliminary first quarter gas consumption data show an overall 7% increase compared
to the first quarter of 1990. While the winter of 1990-1991 was again warmer-than-normal, the heating
degree day accumulation for January through March was 11% greater than in the first quarter of 1990.
Moreover, the fact that September through December of 1990 was 7.9% warmer-than-normal suggests
that the temperature-sensitive segments of the residential and commercial markets are likely to show
growth in the fourth quarter of 1991.
The year-to-date growth in the industrial and electricity generation sectors, which was stronger than
the residential and commercial sectors, was also positively influenced by year-to-year weather changes.
The principal other factor influencing these large volume markets was the low spot gas prices, which
resulted in dual-fuel capable customers choosing gas over oil. Industrial and electric generation use of
natural gas increased 11% in January/February of 1991 compared to the same period in 1990, while oil
use declined 2.3% in these sectors.
While industrial gas demand is expected to continue to outpace 1990 for the remainder of 1991
due to favorable natural gas/oil price spreads, higher hydroelectric production will dampen gas demand
in the electric utility sector. Given the extremely low spot prices, natural gas will effectively compete
against coal (directly and coal-over-wire). Overall, the A.G.A. projection is for flat demand in the low case
relative to 1990 and the potential for gas demand to reach 20.2 quads this year at the high end, with a
base case forecast of 19.8 quads. Should the high case be reached it would be the first time since 1980
that natural gas demand was at the 20 quad level.
TABLE 1
1991 MID - YEAR OUTLOOK
(Quadrillion Btu)
1990¹
1991 A.G.A. Forecast
Low
Base
High
Residential
4.6
4.7
4.8
4.9
Commercial
2.7
2.7
2.8
2.8
Industrial
7.3
7.4
7.5
7.6
Electric Generation
2.9
2.8
2.9
3.0
Subtotal
17.5
17.6
18.0
18.3
Lease & Plant
1.3
1.2
1.2
1.3
Pipeline
0.6
0.6
0.6
0.6
TOTAL
19.4
19.4
19.8
20.2
Percent Gain
-
2.1%
4.1%
1 Energy Information Administration, Monthly Energy Review, May 28, 1991.
© 1991 by the American Gas Association
1515 Wilson Boulevard
Arlington, VA 22209
Summary
Residential and Commercial
The modest rise in residential and commercial gas demand was overwhelmingly related to
weather. Looking to the latter part of the year, the prospect is good for a weather-related increase over
the prior year since September through December of 1990 was 7.9% warmer than normal. Natural gas'
favorable (59%) market share position in new single family housing completions (compared with 33% for
electricity and 5% for oil) and continued strength in conversions to natural gas are other positive factors
in these sectors.
Industrial
The traditional economic indicators, which have turned negative, can not explain the steady growth
in industrial gas consumption. Fuel switching from oil and cogeneration demand (resulting from record
cogeneration filings in the mid-1980's) appear to be more important factors. The recessionary economy
at large, as reflected in a decline in real GNP of 2.8% in the first quarter of 1991 compared to the fourth
quarter of 1990, has been outweighed by the impact of other gas-related factors. A key factor is the
historically low prices for natural gas on the spot market, which has induced large volume users to take
advantage of depressed gas prices relative to coal and oil prices. Energy Information Administration data
for January-April show that both distillate and residual oil supplied to the market were down 5% and 14%,
respectively.
Electric Generation
Natural gas is benefitting competitively from a range of factors influencing fuel use for electricity
generation. The low spot price for gas is a primary reason why gas consumption for electricity generation
has increased in the first quarter, while oil consumption has declined. First quarter data show that while
natural gas consumption was up 10.3% (.049 quads), fuel oil consumption for electricity generation was
down 15.4%. Electricity consumption was up slightly (1.4%) in January and February and is expected to
continue to grow at this reduced rate during 1991.
TABLE 2
First Quarter Comparison
(Quadrillion Btu)
1990¹
1991
1st Q
1st Q
Д%
Residential
2.032
2.153
6.0%
Commercial
1.078
1.130
4.8%
Industrial
1.799
2.001
11.2%
Electric Generation
.475
.524
10.3%
Subtotal
5.384
5.808
7.9%
Lease & Plant
.325
.323
-0.3%
Pipeline
.154
.161
4.6%
Total
5.863
6.292
7.3%
1 Energy Information Administration, Monthly Energy Review, May 28, 1991.
A&A
American Gas
Association
Planning & Analysis
Issues
Issue Brief 1991-3
January 16, 1991
The Role of Natural Gas in
Offsetting Oil: 1991 Update
A. Introduction
The invasion of Kuwait in August has brought the subject of U.S. dependence on oil imports
to the forefront again. America now imports about half of the oil that it consumes. Most oil is
used in the transportation sector, however, a large volume of fuel oil is also used in stationary
applications: for space heating; for industrial process and boiler use; and for electricity generation.
Oil use in stationary applications (excluding feedstocks) in 1989 amounted to 4.9 million barrels per
day (b/d), or the equivalent of 68% of annual crude oil imports. Distillate and residual fuel oil, the
oil products most likely to be offset by gas, make up half of that total. In contrast, natural gas is
essentially a domestic resource with over 40 years of conventional supply under current consumption
rates and the potential to extend the resource base well beyond the next century.
The purpose of this analysis is to demonstrate the extent to which natural gas can directly
contribute to national energy security by substituting for oil in existing applications. This study
updates a similar analysis published by A.G.A. in 1988. This analysis was prepared on a market-by-
market basis over different time horizons: 30-day (immediate); 1 year; 5 years; and a 10-year
potential. This analysis estimates oil displacement potential - it is not a forecast. Such levels would
only be achievable if government policy actively promotes natural gas.
B. Executive Summary
In an emergency or oil supply disruption scenario natural gas could immediately offset 130
thousand barrels per day (mbd) of distillate and residual fuel oil in stationary applications. Within
a year the rate of displacement could increase to 420 mbd as significant penetration in the dual-fuel
capable boiler markets accumulates. After five years, the combination of growing conversions in
the residential and commercial buildings sector (mainly on the East Coast) and further penetration
in boiler and process markets would raise the penetration rate to 1.0 million b/d. If a
comprehensive government initiative was begun now with a 10-year horizon, it is estimated that 1.5
million b/d of fuel oil use could be offset by the end of the decade. Adding 240 mbd that would,
in effect, be offsets of gasoline use in fleet vehicles in the transportation sector, would bring total
oil displacement by natural gas to 1.7 million b/d after 10 years.
© 1991 by the American Gas Association
1515 Wilson Boulevard
Arlington, VA 22209
An important component of this initiative would be increased natural gas pipeline capacity
into oil-dependent regions. The volume of current planned natural gas pipeline capacity would go
substantially toward accomodating the projected level of oil displacements over five years. To
achieve the ten year goal, a similar increment in pipeline capacity and an increase in gas storage
capacity would be needed. The exact size of the increment is dependent upon seasonal load factors
and upon the volume of additional gas load that would derive from economic growth and other new
sources.
The highlights for each stationary market and for the transportation sector for each
succeeding timeframe are as follows and summarized in Table 1:
The residential market for fuel oil is essentially distillate oil use concentrated on the U.S.
East Coast, particularly in the Middle Atlantic census division which accounts for 5.6 million
of the 11 million oil-heated households. Conversions from oil to natural gas heat already
comprise the single largest source of residential conversions annually. Based on previous
conversion growth rates it is possible to envision 350,000 conversions in the first year,
displacing 20 mbd, rising to 500,000 conversions annually by the fifth year, resulting in oil
offsets of 100 mbd after five years. If the annual rate of conversions then holds at 500,000,
the cumulative potential impact after 10 years would be the displacement of 225 mbd of
distillate fuel oil use -- roughly half of the current consumption level. This ten year goal
would require additional pipeline and storage capacity and distribution mains given the
seasonality and location of this load.
In the commercial market, both distillate and residual fuel oil are used - primarily for
spaceheating, but also for water heating in large multi-family buildings. Similar to the
residential sector, commercial fuel oil consumption is also concentrated on the East Coast,
but to a lesser extent. In the event of an oil supply disruption, displacement of oil use in
dual-fuel boilers could reach 25 mbd. After a year, the displacement of all oil in gas-served
buildings, as well as in a portion of the more than three million multi-family units with gas
service nearby, would increase the offsets to 100 mbd. With increased penetration in the
multi-family sector, the offsets could reach 190 mbd after five years and as much as 250 mbd
after 10 years, or nearly 65 percent of the current level of commercial fuel oil use.
The industrial market is the largest stationary market for fuel oil. Even after discounting
those oil applications for which natural gas is not suited for displacement (such as
feedstocks, asphalt and vessel bunkering) there remains nearly 900 mbd of distillate and
residual fuel oil use in boiler and process applications that theoretically could be displaced
by natural gas. Oil offsets could rise from 50 mbd in the immediate term to 200 mbd after
a year. This would occur predominantly in dual-fuel boiler applications where gas and
residual oil, in particular, are intensely competitive. After five years, when gas penetrates
more into the applications using distillate oil, the offsets are projected to increase to 400
mbd. If there is, in fact, a policy designed to minimize the use of oil in industrial
applications, the extension of gas service to a high proportion of what had formerly been
unserved customers could potentially see the level of offsets reach 600 mbd after 10 years.
While certainly a large volume, this would only be about 15 percent of all the oil
consumption (including LPG) in the entire industrial market and two-thirds of the
residual/distillate oil use. Like the residential and commercial sectors, displacement of oil
in the industrial market to meet the ten year goal will require significant new construction
of pipeline and distribution infrastructure. Seasonal service arrangments would also have
to be enhanced.
2
Fuel oil consumption (almost entirely residual oil)in the electric utility market is heavily
concentrated on the East Coast. Over 80 percent of this oil consumption occurs in the three
census divisions along the Atlantic. Unlike the industrial market, which is made up of
thousands of customers and more widely distributed, the number of power plants involved
is relatively small. About 125 of the 290 or so power plants that use fuel oil are on the East
Coast -- and some of these plants are already dual - fuel capable. Consequently, the
potential for oil offsets rises quickly from 50 mbd in the very short - term to 300 mbd after
five years. With a concentrated national effort, three - quarters of fuel oil consumption
could be offset in 10 years, reaching 400 mbd. Given the location of these plants, it is likely
many plants would choose to be dual-fuel capable, interruptible gas customers. Thus
complete displacement of oil year-round would be unlikely.
In the transportation sector the displacements would be limited in the early years,
reflecting the fact that a natural gas vehicle (NGV) manufacturing and fuel distribution
infrastructure is now beginning to develop. The oil displacement rate would move up
from minimal levels in the first five years, rising quickly by the end of the decade to 240 mbd
as 2 million centrally-refueled fleet vehicles in major urban areas convert to natural gas. The
passage of the Clean Air Act of 1990 alone will spur oil offsets in the transportation sector.
Table 1
Potential Oil Substitution
(thousand barrels/day)
Stationary Sources
Immediate
One-Year
Five-Years
Ten-Years
Residential
5
20
100
225
Commercial
25
100
190
250
Industrial
50
200
400
600
Electric Generation
50
100
300
400
Subtotal
130
420
990
1475
Mobile Sources
Vehicles
-
-
5
240
Total
130
420
995
1715
Note: NGV market penetration grows dramatically after five years as a result of the new
Clean Air Act legislation which begins to take effect in 1995. A.G.A. forecasts that by the
year 2005 natural gas vehicles could displace as much as 675 mbd.
3
AGA
American Gas
Association
Energy
Analysis
1515 Wilson Boulevard
A.G.A. Planning & Analysis Group
Arlington, Virginia 22209
EA 1991-5
April 16, 1991
Natural Gas and Electric Vehicles --
An Economic and Environmental Comparison with Gasoline Vehicles
A.
Introduction
Alternative fuel vehicles -- i.e., vehicles operating on something other than
conventional gasoline --- have faced a variety of hurdles in the marketplace.
Despite numerous potential benefits, including environmental, energy security,
and, in some cases, economic advantages, penetration by alternative fuel vehicles
has been extremely limited to date. The existence of an extensive infrastructure
for conventional gasoline vehicles, from vehicle production and maintenance to
fuel distribution, has, in the past, proved to be a nearly insurmountable obstacle.
The outlook for alternative fuel vehicles has changed dramatically over the
past year. Heightened environmental concerns culminated in the passage of the
federal Clean Air Act Amendments of 1990 as well as in related state legislation.
Primarily as a result of environmental legislation, and, to a lesser extent due to
increasing concerns regarding world oil supply security and price, as many as 10
million alternative fuel vehicles are projected to be on the road by 2005. 1 These
vehicles will be powered by natural gas, propane, electricity, methanol, ethanol
and whatever other energy forms can meet the pollution reduction mandates of
the law and the economic dictates of the marketplace.
The purpose of this analysis is to compare the projected mid-1990s
economics and environmental impacts of two of the cleanest alternative fuel
competitors -- natural gas and electricity -- with a conventional gasoline vehicle
meeting the tougher emission standards that will be in place at that time. This
analysis considers not only the vehicle per se, but also the ancillary environmental
impacts attributable to fuel production, processing, transportation, conversion and
distribution -- i.e., the "full cycle" impacts. In terms of economics, the analysis
includes both the cost of vehicle purchase as well as operating costs.
© 1991 by the American Gas Association.
2
B.
Executive Summary
Economics. The mid-1990s cost of purchasing and operating natural gas
vehicles (NGVs) is projected to be 4 percent less than the costs associated with
conventional gasoline vehicles, and 23 to 35 percent less (range depends on
battery life) than the costs of electric vehicles. See Exhibit 1.
The capital cost of the baseline gasoline vehicle (light-duty minivan, 1991
dollars) is $14,000, 7 percent less than the projected cost of a comparable
factory built NGV ($15,000), and 36 percent less than the original cost of
an electric van ($21,850). The costs of the NGVs and electric vehicles
assume mass production by the mid-to-late 1990s.
-
Based on a 7-year operating life for the fleet van at 18,500 miles per
year, the capital cost of the gasoline van is 10.5c per mile versus
11.3c per mile projected for the NGV.
The cost of the electric van is projected to be significantly higher,
ranging from 16.4c to 20.4c per mile over its useful life of
approximately 130,000 miles.
The present value of the operating cost (fuel, fuel taxes, maintenance and
repairs) of the NGV is projected to be 20 percent less than the operating
cost of the gasoline vehicle -- 5.7c per mile versus 7.2c per mile. This 1.5c
per mile operating cost advantage more than offsets the purchase price
disadvantage of the NGV.
The electric vehicle -- under relatively optimistic assumptions with respect
to vehicle efficiency and electricity pricing -- is also projected to enjoy
about a 20 percent operating cost advantage relative to the baseline
gasoline vehicle. This advantage, however, cannot offset the capital cost
penalty of the electric vehicle which is 56 to 94 percent greater than that of
the baseline gasoline vehicle.
Environmental. NGVs offer significant potential emission reductions
relative to gasoline in each of the five air pollutants analyzed, ranging from a 14
percent reduction in nitrogen oxides to a 90 percent reduction in carbon
monoxide. (See Exhibit 2.) When the full cycle emissions associated with
electricity generation are included, NGVs were also found to be superior to
electric vehicles in terms of sulfur dioxide, nitrogen oxides and carbon dioxide
emissions, while electric vehicles were cleaner for two categories -- nonmethane
hydrocarbons and carbon monoxide. The incremental reduction from electric
vehicles relative to NGVs for these two pollutants is, however, minor.
Exhibit 1
Economic Comparison of Conventional Gasoline,
Electric and Natural Gas Vehicles
(Cents per Mile)
c/Mi.
30
25
20
15
10
5
0
Conventional
Natural
Electric
Electric
Gasoline
Gas
Vehicle 1
Vehicle 1
Operating
Capital
1
Lower end of range for electric vehicles based on 7 year battery life (129,500mi.);
upper end based on 3.5 year life (64,750 mi.).
Source: See Section D-- Economic Methodology.
Exhibit 2
Vehicular and Other Emissions Attributable to
Conventional Gasoline, Electric and Natural Gas Vehicles
(Index, 100 = Most Polluting Cycle)
Nonmethane Hydrocarbons
Carbon Monoxide
Nitrogen Oxides
.55 gpm
3.57 gpm
1.00 gpm
100%
100%
100%
.64 gpm
.55 gpm
50%
50%
50%
.08 gpm
.36 gpm
.02 gpm
.07 gpm
CG
NGV
EV
CG
NGV
EV
CG
NGV
EV
Sulfur Dioxide
Carbon Dioxide
Solid Wastes
2.29 gpm
454 gpm
24 gpm
100%
100%
100%
400 gpm
273 gpm
50%
50%
50%
.16 gpm
n
n
n
CG
NGV
EV
CG
NGV
EV
CG
NGV
EV
CG: Conventional Gasoline VehicleEmissions
NGV: Natural Gas Vehicle Emissions
EV: Electric Vehicle Emissions
Vehicle
Other
Vehicle
Other
Other
Note: "Other" emissions refers to emissions from production, processing, conversion, transportation and distribution of energy to vehicle.
gpm: Grams Per Mile
n
: Negligible, less than .005 gpm
5
Nonmethane hydrocarbons (NMHC) are one of the primary precursors of
urban ozone or smog. NMHC emissions attributable to NGVs of 0.08
grams per mile (gpm) are only 15 percent of those estimated for
conventional gasoline vehicles -- 0.55 gpm. Electric vehicles, with NMHC
emissions of 0.02 gpm, offer even further reductions.
Carbon monoxide (CO) is an air pollutant that is particularly troublesome
in high-altitude urban areas such as Denver. NGVs can reduce CO
emissions relative to conventional gasoline vehicles by 90 percent -- 0.36
gpm versus 3.57 gpm -- while CO emissions attributable to electric vehicles
are 0.07 gpm.
Nitrogen oxides (NOx) are generally believed to be a secondary contributor
to acid rain, and, in some geographic areas, ozone formation. NGVs can
reduce the NOₓ attributable to electric vehicles by some 45 percent -- 0.55
gpm versus 1.00 gpm -- and by some 14 percent relative to conventional
gasoline vehicles (0.64 gpm).
Sulfur dioxide (SO₂) is the primary precursor of acid rain. NGVs and their
supply system produce virtually no SO2, whereas SO₂ emissions attributable
to electric vehicles and conventional gasoline vehicles are 2.29 gpm and
0.16 gpm, respectively.
Carbon dioxide (CO2) is the primary greenhouse gas thought to contribute
to global warming. The CO2 emissions attributable to electric vehicles --
454 gpm -- are more than 65 percent higher than those of the NGV (273
gpm). The CO2 of the conventional gasoline vehicle, at 400 gpm, is just
over 50 percent greater than that of the NGV.
Methane, the primary component of natural gas, is also thought to
be a contributor to global warming. Estimates regarding the climate
tradeoff between NGVs and gasoline vehicles are subject to
considerable uncertainties, with the climate impact of the NGV
estimated to be 0-40 percent less than the gasoline vehicle, with a
base case of 21 percent less.
The generation of electricity by oil and coal also results in the production
of solid waste and sludge. Solid waste production by generating units
supplying energy to electric vehicles is significant, at some 24 gpm. NGVs
result in no sludge or ash production.
It should be noted that the results of this analysis are dependent on a
variety of assumptions regarding each of the vehicle types. (See Sections D and F
-- Methodology.) In particular, emissions attributable to electric vehicles are
6
largely dependent on the assumptions regarding how the electricity is generated.
This analysis is based on the 1995 projected national average fuel mix for
electricity generation -- 73 percent fossil fuels and 27 percent non-fossil (assumes
no air or solid waste pollution, which overstates the benefits of renewables). The
generating mix in some parts of the country, California in particular -- where
electric vehicles are expected to be most successful in the short run -- is far
"cleaner" than the national mix. Most electricity generated in California is via
natural gas, low sulfur oil and hydro-power. This analysis overstates the
environmental impacts of such areas, but understates the impacts in more coal-
dependent regions. It should also be noted that the conventional gasoline vehicle
used as a baseline in this analysis is significantly cleaner than a 1991 vehicle -- by
60 percent or more for some of the pollutants. Thus, the reduction potential of
both NGVs and electric vehicles is even more impressive when compared with
today's cars.
C.
Background
The mobile source provisions of the Clean Air Act Amendments of 1990,
coupled with various state programs such as the clean fuels program in California,
ensure that the market penetration of clean alternatives to gasoline will increase
in the 1990s. Much of this market penetration will focus on "fleet" vehicles -- e.g.,
taxis, delivery vans, school buses and other fleets of various types and sizes.
There are some 13 million fleet vehicles in the U.S. today, accounting for about
6.5 percent of the total vehicle population and 10 percent of total vehicular energy
consumption. This high energy consumption per vehicle is one of the features
that makes fleets particularly attractive alternative fuel candidates. Additionally,
fleets return to a central location making vehicle refueling and maintenance
operationally more efficient and more economic.
The comparisons in this analysis are based on the expected performance of
natural gas, electric and gasoline vehicles in the mid-1990s. Gasoline vehicles
converted to natural gas are on the road today, and in most cases are cleaner than
gasoline vehicles. However, light-duty vehicles dedicated to run exclusively on
natural gas and optimized for natural gas operation are not yet available.
Similarly, advances in electric vehicles are expected prior to any large-scale
production.
This analysis is based on a light-duty minivan. This type of vehicle is
suitable for fleet operations, transporting either people or light cargo. NGVs will
also compete in the medium- and heavy-duty markets, but electric vehicles will
probably not, due to power limitations. Fuel efficiency -- assumed equal on a Btu
basis for natural gas and gasoline -- is assumed to increase to 25 miles per gallon
by the mid-1990s, versus just under 20 mpg today.² The electric vehicle is a
Chrysler TEVan, with a nickel-iron battery, and an energy consumption of 0.5
7
kilowatt hours per mile. The van, for which production is projected in the early
1990s, has an estimated range of 120 miles. The battery charger has an energy
efficiency of 90 to 95 percent, and the battery itself is 70 to 75 percent efficient.³
D.
Economic Methodology and Assumptions
The economic comparison presented in this analysis considers the costs of
purchasing and operating a new light-duty van used for fleet-type operation. Each
van considered -- gasoline, NGV or electric -- was assumed to be purchased new,
driven 18,500 miles per year, and scrapped after 7 years of operation (129,500
miles) with no salvage value. This is not the typical turnover pattern of most
commercial fleets, which tend to sell their vehicles before their useful life is
completed, but determining the resale value of vehicles not yet in production is
highly speculative.
Both the operating and capital components for all vehicles are reflective of
today's costs. However, the incremental capital costs of the dedicated NGV and
electric vehicle are based on the assumption of mass production by the mid-1990s.
The most problematic economic assumption is that of the useful life of
batteries for electric vehicles. Batteries account for about one-third the cost of an
electric vehicle, and battery replacement after one or two years would seriously
reduce the competitiveness of the vehicle. Some proponents are projecting a 9- to
10-year life for nickel-iron batteries currently being developed, but not yet proven.
Based on experience to date, and on the higher mileage requirement assumed in
this analysis for fleet vehicles -- about double that of a passenger vehicle OM a 7-
year life-span was assumed for batteries. An alternative case with a 3 ½-year life
was also considered, reflecting a still significant, yet more moderate rate of
technological improvement.
Vehicle Cost
The baseline gasoline vehicle is a minivan with an initial cost of $14,000
(see Exhibit 3). The NGV has an incremental capital cost of approximately $800,
primarily for fuel cylinders.4 In addition, a $200 premium was applied to the
NGV due to anticipated high demand, bringing the total capital cost to $1,000.
The clean fuel premium may be higher than this initially, but will taper off as the
California pilot program and federal fleet programs accelerate (1996-1998) and
production levels expand. The incremental cost of the electric vehicle is $7,800 --
about 97 percent of which is attributable to the batteries.⁵ The electric vehicle
also requires a battery charger, with a cost of roughly $100 per vehicle in fleet
situations. All vehicles were assumed to be purchased over 48 months at a 10
percent interest rate, with 80 percent financing and a 12 percent nominal discount
factor. The present value of the costs of vehicles were allocated over the 7-year
8
Exhibit 3
Economic Comparison of Conventional Gasoline, Electric and
Natural Gas Vehicles
Initial
Capital Cost
Gasoline
Natural Gas
Electric
Base Vehicle
$14,000
$14,000
$14,000
Other
-
1,000
7,850
Total ($)
$14,000
$15,000
$21,850
(c/mi.)
10.52c
11.27c
16.42c-20.43c
Operating
Costs (e/mi)
Energy
3.62
1.58
2.86
Energy Tax
1.24
1.24
1.24
Compression
-
.67
-
Oil
.17
.15
-
Tires
.40
.40
.50
Maintenance
1.74
1.65
1.10
Total
7.17c
5.69c
5.70c
Total Cost (c/mi.)
(Capital & Operating)
17.69c
16.96c
22.12c-26.13c¹
Source: See Section D -- Economic Methodology.
¹Lower end of range for electric vehicles based on 7-year battery life; upper end based on 3 1/2-year
life.
9
129,500 mile life. The cost per mile of the gasoline vehicle is 10.5c, roughly 5
percent less than the NGV's cost of 11.3c. The per-mile vehicle cost of the
electric vehicle is 16.4c assuming a 7-year battery life, and 20.4c assuming a 3½-
year life -- 56 to 94 percent greater than that of the base gasoline vehicle.
Energy Costs
The greatest expense associated with operating a vehicle is the cost of
purchasing energy -- gasoline, natural gas or electricity. A 1990 gasoline cost of
90.4c per gallon (excluding taxes),⁷ coupled with a fuel efficiency of 25 mpg,
translates into an energy cost of 3.6c per mile for the base vehicle.
Natural gas was assumed to be sold through a slow-fill fleet-operated
refueling station at the national average 1990 industrial gas rate for gas utility
sales of $3.15 per MMBtu, excluding compression, see below.⁸ Although
dedicated NGVs may require fewer Btu per mile than comparable gasoline
vehicles in the mid-1990s, supporting data is not demonstrable at this time and an
equivalent fuel efficiency was assumed. The fuel cost per mile for NGVs is
therefore 1.6c -- only about 45 percent of the gasoline vehicles fuel cost.
Electric vans were assumed to require 0.5 kilowatt hours (kwh) per mile,¹⁰
with 30 percent of the power purchased at the 1990 national average commercial
rate of 7.4c per kwh, 11 and the remaining 70 percent purchased at an off-peak rate
of 5e per kwh. Some proponents assume electric vehicles will only recharge at
night and pay about one-third less for electricity. This assumption seems
unreasonable based on the operating characteristics of fleet vehicles. The 70
percent off-peak recharging assumed herein is reasonable, and probably generous.
Based on these energy requirements and prices, both of which appear optimistic,
the energy component is 2.9c per mile -- 20 percent less than for the gasoline
vehicle, but 80 percent more than for the NGV.
The current national average gasoline tax -- combined state and federal --
is 31c per gallon, or 1.2c per mile. Federal gasoline taxes, as well as those in
some states, are not currently applied to NGVs or electric vehicles. One could
argue that this exclusion should continue in order to stimulate the development of
these clean alternatives to imported oil. However, a conservative assumption was
made that the per mile tax on each vehicle would eventually be the same, based
in part on the budgetary pressure faced by many state highway departments. (On
a Btu-per-mile basis, the NGV and gasoline vehicles were assumed to be equal,
while electric vehicles powered by fossil fuel-based electricity would require about
15 percent more Btu into the generating station.)
The final fuel cost component, applicable only to NGVs, is attributable to
the cost of compressing and dispensing natural gas at the refueling station. This
10
analysis assumes that fleet operators will refuel NGVs in a slow-fill mode as
opposed to a more costly 5 minute quick-fill. The slow fill mode requires less
compression, although it is hoped that quick-fill refueling as economic as the slow
fill included herein will be available in the mid- to late-1990s. Advances in
compression equipment, and the proliferation of high volume, low cost public
refueling stations will decrease the cost of quick fill operations. There are
approximately 125 public NGV refueling stations operational in the U.S. today.⁹
The slow-fill refueling cost, based on recovering both the capital cost of building
the station and associated operating costs, is roughly $1.35 per million Btu
(MMBtu)¹² of fuel dispensed, or 0.7c per mile of vehicular travel.
Other Operating Costs
The maintenance and repair costs associated with fleet gasoline vehicles is
1.7c per mile, with an additional 0.2c per mile for oil changes. 13 The combined
cost for NGVs is 1.8c per mile, about 10 percent lower for oil changes and 5
percent lower for other maintenance. The electric vehicle requires no oil
changes, and other maintenance is about two-thirds that of the base gasoline
vehicle based on various published studies. 14
Tire replacement for the base gasoline vehicle costs 0.4c per mile¹⁵ versus
0.5c per mile for the electric vehicle. The higher replacement rate for the
electric vehicle is due to its greater weight -- about 25 percent -- attributable to
the batteries. The NGV would also have incremental weight due to the fuel
cylinders, but tanks in the mid 1990s will be lighter, and this incremental weight
will be offset by the removal of the gasoline tank and the lower weight of natural
gas relative to gasoline. Thus, tire costs were assumed equal for NGVs and
gasoline vehicles.
E.
Economic Conclusions
The total cost of purchasing and operating an NGV is 17.0c per mile,
about 4 percent less than the cost of the gasoline vehicle (17.7c per mile), and 23
to 35 percent less than the cost of the electric vehicle (22.1 to 26.1c per mile).
The operating costs of the NGV and electric vehicle are similar, at 5.7c per mile,
about 20 percent less than the gasoline vehicle -- 7.2c per mile. This operating
cost savings more than offsets the $1,000 incremental capital cost of the NGV, but
not the $7,850 incremental cost of the electric vehicle.
A simple payback analysis indicates that the additional cost of the NGV
would be recovered in less than 3 years of operating savings.
Payback analyses
are very rough indicators, and vary greatly from vehicle to vehicle. NGVs with
less costly cylinders, greater mileage requirements, higher fuel efficiency or those
not subject to full taxation would have significantly shorter payback periods.
11
F.
Environmental Methodology and Assumptions
Clean fuel vehicles will differ with respect to the types of pollution they
can reduce, the degree of reduction they can achieve, and the location of the
pollution they produce. The latter point is clearly demonstrated by electric
vehicles which produce no tailpipe emissions, yet cannot be viewed as pollution
free. For example, the generation of coal-fired electricity produces a variety of
air, water and solid waste pollutants, as does the production, processing and
transportation of the required fossil fuel to the generating station.
The purpose of this environmental analysis is to quantify the vehicular and
other pollutant emissions associated with NGVs and electric vehicles relative to a
conventional gasoline vehicle. The comparison is based on "typical" fleet vehicles
expected to be in operation by the mid-1990s, and complying with O: exceeding
the emission requirements that will then be in place.
This analysis compares the energy consumption and environmental impacts
not only of the vehicle itself, but also of the fuel production, processing,
transportation and conversion "trajectory." Total environmental impacts depend
on both the efficiency of the various segments of the trajectory, as well- as the
emissions of those segments. That is, less efficient vehicles require a greater
energy input, which in turn requires greater levels of fuel production, processing,
etc. -- with greater resultant emissions.
Conventional Gasoline Vehicles
The baseline vehicle in this analysis is assumed to run on conventional
gasoline, as opposed to the "reformulated" gasoline that will be required in nine
urban areas in the latter half of the 1990s. Little public data is available
regarding the emission reduction potential of reformulated gasoline. The baseline
vehicle is far cleaner than today's gasoline vehicle; however, emission standards
will be much tighter for all vehicles purchased in the U.S. in the mid-1990s.
NMHC emissions of the gasoline vehicle were estimated at 0.40 gpm based
on the tailpipe standard of 0.25 gpm, added to evaporative emissions of 0.15 gpm¹⁶
(see Exhibit 4). These figures reflect the fact that refueling evaporative emissions
must be reduced by 95 percent according to the Clean Air Act Amendments,
while hot soak and running evaporatives will be required to be controlled to the
"greatest extent possible." Non-vehicle NMHC emissions, primarily from the
refining process, are 0.15 gpm,¹⁷ bringing the total to 0.55 for the vehicle and its
fuel supply trajectory.
Tailpipe emissions of CO from gasoline vehicles are very high -- 3.40 gpm
of the 3.57 gpm total for the gasoline trajectory. This is despite the reduction in
12
the CO standard for gasoline vehicles to 3.40 gpm from today's level of more than
10 gpm.
NOₓ emissions of the gasoline trajectory total 0.64 gpm, split between
tailpipe and other emissions at a rate of roughly 2:1. The total is about two-thirds
that of the electric vehicle, but about 15 percent greater than the NGV due to
higher non-vehicle emissions.¹⁸ The tailpipe emissions of gasoline vehicles and
NGVs are assumed to be equal at the standard of 0.4 gpm.
SO₂ emissions are quite low for the gasoline trajectory -- 0.16 gpm. Only
0.04 gpm is from the tailpipe; three-fourths of the total is from non-tailpipe
sources, primarily the refinery.¹⁹
Over 85 percent of the 400 gpm CO2 total is attributable to the tailpipe
emissions of the gasoline vehicle. Tailpipe CO₂ emissions are based on a factor of
19 pounds of CO2 per gallon of gasoline consumed.²⁰
Estimates were not available for the solid wastes attributable to the
gasoline vehicle trajectory, and they were therefore assumed to be negligible.
Some sludge would result from oil storage and processing, but the amount would
be minimal on a gpm basis.
Natural Gas Vehicles
Tailpipe NMHC emissions of 0.07 gpm were estimated for NGVs. This
emission rate, which is below the federal fleet standard and would comply with
the California Low Emission Vehicle standard, is believed achievable in the time
frame of this analysis based on testing of vehicles not dedicated for natural gas
operation, and also on projections of the Environmental Protection Agency
(EPA).²¹ The NMHC total is 85 percent less than the gasoline total, but slightly
higher than the electric vehicle total.
NGVs have been proven to have very low CO emissions relative to
gasoline vehicles. A 90 percent reduction from the gasoline standard was
assumed herein, based on various vehicle test results and studies by EPA. 22 The
CO total is 0.36 gpm, with a minimal contribution of 0.02 gpm from non-tailpipe
emissions.
NO, is one of the more difficult pollutants to control in NGVs, especially
when the emissions of other pollutants are also held at very low levels. It was
assumed that NGVs would do no better than the Phase I standard of 0.4 gpm, the
same as gasoline vehicles. An additional 0.15 gpm of NOₓ is attributable to other
segments of the natural gas trajectory, primarily from compressor stations used in
gas transportation. Compressor station NOₓ emissions from EPA's AP 42²³ of 1.3
Exhibit 4
Vehicular and Other Emissions Attributable to Gasoline and Alternative Fuel Vehicles
(grams per mile)
Natural Gas
Electric
Gasoline
Vehicle
Other
Total
Vehicle
Other
Total
Vehicle
Other
Total
NMHC
.07
.01
.08
--
.02
.02
.40
.15
.55
CO
.34
.02
.36
--
.07
.07
3.40
.17
3.57
NO,
.40
.15
.55
--
1.00
1.00
.40
.24
.64
SO₂
n
n
n
--
2.29
2.29
.04
.12
.16
CO2
261
12
273
--
454
454
345
55
400
Solid Waste
n
n
n
-
24
24
m
n'
n
13
Source:
See Section F, Environmental Methodology.
n:
Negligible, less than .005 gpm
NMHC:
Nonmethane hydrocarbons
CO:
Carbon monoxide
NO,:
Nitrogen oxides
SO₂:
Sulfur dioxide
CO2:
Carbon dioxide
Solid Waste: Sludge and ash
14
grams/brake horsepower-hour for turbines and 11 grams/brake horsepower-hour
for reciprocating engines was assumed. Operating hours in 1988 of 16.6 billion
horsepower-hours for turbines and 39.1 billion for engines was assumed based on
data collected by A.G.A. Total NOx emitted was calculated and divided by gas
throughput in 1988, and converted to grams per mile of vehicular travel.
CO2 emissions of 273 gpm were calculated for NGVs, about 20 and 40
percent less than the CO2 emissions attributable to the gasoline and electric
trajectories, respectively. Ninety-six percent of the NGVs CO2 emissions are
attributable to the vehicle, based on an emission rate of 115 pounds of CO2 per
MMBtu of fuel consumed.²⁴ The remaining 12 gpm is largely from pipeline
compressor stations, which consume about 3.8 percent of the total gas throughput.
Assuming a global warming potential (gwp) (mass basis -- 100-year
horizon) of 21,2 a one percent loss²⁶ rate for natural gas operations, and 1 gpm of
tailpipe methane emissions, the net effect of using natural gas as a vehicular fuel
instead of gasoline would be approximately a 21 percent reduction in the
greenhouse impact of the vehicle. Assuming a very conservative gwp of 60 the
NGV and gasoline alternatives would be equal from a climate perspective, while
the NGV would be superior by 40 percent, assuming a 25 percent improvement in
NGV efficiency compared with the gasoline vehicle.
The NGV trajectory produces no CO2, sludge or ash. NGVs are also
expected to reduce tailpipe toxic emissions by some 90 percent according to EPA,
a point not explored in this analysis.²⁵
Electric Vehicles
There are no air or solid waste emissions from the electric vehicle itself.
Thus, total emissions attributable to the electric vehicle are primarily dependent
on the energy source used to generate the electricity, and the pollution controls, if
any, at the generating site. If all electricity were supplied by solar, wind or hydro
power, the electric vehicle would be pollution-free from the standpoint of the
pollutants considered in this analysis. On the other hand, if all electricity were
provided by uncontrolled high sulfur coal units, the electric vehicle would be far
from environmentally benign. For example, the generating mix in California is far
"cleaner" than the mix in most other states. Therefore electric vehicles, which are
expected to be initially most successful in California, will have less adverse
environmental impacts there than in other states.
This analysis is based on the assumption that electricity will be supplied by
the national average generating mix projected to be in-place in 1995 -- which is
only slightly different from that which is in-place today. About 90 gigawatts (GW)
of capacity is projected to be added by 1995 to the currently in-place total of 750
15
GW.2⁸ It is projected that some 60 GW will be electric utility capacity, split
between natural gas, coal and "other" sources at roughly one-third each. Non-
utility generators will add about 30 GW, with some three-fourths of this capacity
gas-fired and the bulk of the remainder coal-fired. In all, the portion of electricity
provided by gas will increase to 13 percent from today's 9 percent level. The oil
share will drop slightly, but remain at just over 5 percent, while coal drops from
57 to 55 percent. "Other" sources, including nuclear, hydro and miscellaneous
sources, fall from 28 to 27 percent of the total. Thus, 27 percent of the energy
supplied to the electric vehicle was assumed to be pollution free. The remainder
was assumed to be controlled to at least the extent required by law.
Emissions of NMHC and CO attributable to the electricity trajectory are
extremely low -- 0.02 gpm and 0.07 gpm, respectively. Emissions of the
conversion segment were taken from EPA's AP-42,29 all other emissions were
derived from Hittman. 30 NOₓ emissions of 1.00 gpm attributable to electric
vehicles are significant. Over 97 percent of the NOₓ total comes from generating
units. Existing uncontrolled oil and gas boilers each emit roughly a half a pound
of NOx per MMBtu, while uncontrolled coal boilers emit a full pound. New gas
and oil units were assumed to be combined cycle plants with reduced emissions of
0.15 pounds per MMBtu. New coal units and existing units "affected" by the clean
air act Phase I requirements were assumed to meet the required low NOₓ burner
rate of 0.5 pounds per MMBtu. The overall weighted average for fossil fuel units
is 0.75 pounds per MMBtu, and zero for all other units.
Sulfur dioxide emissions attributable to the electric vehicle -- 2.29 gpm --
are far higher than the natural gas or gasoline options. Virtually all of these
emissions are from the generating plant. The current weighted average SO₂
emission rate for fossil fuel generating units is approximately 1.65 pounds per
MMBtu, projected to drop to 1.2 pounds per MMBtu³¹ as more gas and new
controlled coal units are added, in addition to the retrofitting of existing coal units
required by the clean air act amendments.
Emissions of CO2 attributable to electric vehicles are 454 gpm, about the
same as the conventional gasoline total and 66 percent greater than those
attributable to the NGV. Roughly three-fourths of the CO2 emissions are
attributable to the generating plant, the remainder is primarily attributable to oil
refinery operations and the transportation of gas, oil and coal to the generating
unit. The carbon content of the fuel determines the CO2 emission level --
approximately 115 pounds per MMBtu for natural gas, 170 pounds per MMBtu
for residual oil, and 206 pounds per MMBtu for coal.³²
Electricity generation via coal or oil produces significant amounts of solid
waste in the form of sludge and ash. (Electric vehicles may also produce a solid
waste problem as a result of battery disposal, but the magnitude of this problem
16
is, as yet, unclear, and not treated in this analysis.) Sludge is a semi-solid waste
that results primarily from SO₂ scrubbers and liquid waste treatment processes.
Approximately 1 acre/foot is produced annually per megawatt of scrubbed
generating capacity.33 Ash is also produced as a result of coal combustion,
collected both in electrostatic precipitators and in boilers as bottom ash. A
combined solid-waste total of 950,000 tons per year per 1,000 MW for scrubbed
coal units, 450,000 tons per year per 1,000 MW for residual oil units, and 250,000
tons per year per 1,000 MW for unscrubbed coal units, was used. 34 No solid waste
was assumed to originate from gas or other units. Based on an average of 18,500
miles per year per vehicle, these solid waste totals translate to some 24 gpm.
G.
Environmental Conclusions
Significant reductions in the emissions of air pollutants associated with
urban air quality -- NMHC, CO and NOₓ -- are achievable by substituting NGVs
and/or electric vehicles for conventional gasoline vehicles. These air quality
improvements are achievable in spite of the fact that the gasoline vehicle of the
mid-1990s will be far cleaner than that available today. Electric vehicles result in
somewhat lower emissions of NMHC and CO relative to NGVs, while the
opposite is true for NOx. (In fact, NOₓ emissions of the electric vehicle trajectory
are about 35 percent higher than the conventional gasoline trajectory.) In terms
of global warming (CO₂), acid rain (SO₂) and solid waste disposal, NGVs are
clearly superior to either electric or conventional gasoline vehicles.
17
Footnotes
¹American Gas Association, Projected Natural Gas Demand From Vehicles Under the Mobile Source
Provisions of the Clean Air Act Amendments, Energy Analysis 1991-2, (Arlington, VA: Jan 30, 1991)
p.4.
²U.S. Department of Energy, Office of Policy, Planning and Analysis, Assessment of Costs and Benefits
of Flexible and Alternative Fuel Use in the U.S. Transportation Sector, Technical Report Four,
(Washington, DC: August 1990) p. 6.
³DeLuchi, Wang and Sperling, "Electric Vehicle: Performance, Life-Cycle Costs, Emissions and
Recharging Requirements," published in Transpor. Res., -A," Vol. 23A, No. 3., (Great Britian, 1989),
pp. 255-279.
⁴U.S. Department of Energy, Op. Cit, p. 30.
⁵U.S. Department of Energy, Op. Cit, p. 43.
⁶DeLuchi, Wang and Sperling, Op. Cit, p. 263.
U.S. Department of Energy, Energy Information Administration, Monthly Energy Review,
(Washington, DC: February 1991) p.74. Price of 116.4c/gal. for unleaded regular minus 26c/gal.
taxes.
⁸American Gas Association, Monthly Gas Utility Statistical Reports, (Arlington, VA: various issues,
data for December preliminary).
⁹American Gas Association, Directory of Natural Gas Vehicle Refueling Stations Products and
Services, (Arlington, VA: February 1991).
¹⁰U.S. Department of Energy, Op. Cit, p. 42.
"U.S. Department of Energy, Energy Information Administration, Monthly Energy Review,
(Washington, DC: February 1991) p. 101.
"American Gas Association, An Analysis of the Economics and Environmental Effects of Natural Gas
as an Alternative Fuel, Energy Analysis 1989-10, (Arlington, VA: Dec. 15, 1989) p. 7.
¹³Bobit Publications, Automotive Fleet Fact Book, (Redondo Beach, CA: 1988) p. 23.
¹⁴DeLuchi, Wang and Sperling, Op. Cit, p. 264.
¹⁵Bobit Publications, Op. Cit, p. 28.
18
"Evaporative emissions from refueling assumed to drop by 95 percent from today's level (.07 gpm) as
required by clean air act. Hot soak and running losses, which must be controlled to the greatest extent
possible, assumed to drop by more than 50 percent based on discussions with EPA.
¹Hittman Associates for National Science Foundation, EPA and CEQ, Environmental Impact,
Efficiency and Cost of Energy Supply and End-Use, (Columbia, MD: November 1974).
¹⁸Ibid.
19Ibid.
20David Gushee, Congressional Research Service Report to Congress, Carbon Dioxide Emissions From
Methanol as a Vehicle Fuel, (Washington, DC: January 1989) p. 4.
²¹Christopher Weaver, Natural Gas Vehicles and the Environment, Summary Report, preliminary draft,
(Rancho Cordova, CA: August 1990) p. 15.
²U.S. Environmental Protection Agency, Office of Mobile Sources Analysis of the Economic and
Environmental Effects of Compressed Natural Gas as a Vehicle Fuel, Vol. I, (Washington, DC: April
1990) p. 31.
²³U.S. Environmental Protection Agency, OAQPS, Compilation of Air Pollutant Emission Factors,
(Research Triangle Park, NC: August 1977) p. 3.3.2-2.
2⁴American Gas Association, Identification of Errors in Science Concepts, Inc. Greenhouse Paper,
Issue Brief 1989-13, (Arlington, VA: Aug. 25, 1989).
25ICF Incorporated for U.S. EPA, Preliminary Technical Cost Estimates of Measures Available to
Reduce U.S. Greenhouse Gas Emission, (Fairfax, VA: August 1990) p. 4.
2⁸Intergovernmental Panel on Climate Change, Methane Emissions and Opportunities for Control,
(Washington, DC: September 1990).
²⁷U.S. Environmental Protection Agency, Office of Mobile Sources, Op. Cit, p. 33.
2⁸North American Electric Reliability Council, Electricity Supply and Demand 1989-1998, (Princeton,
NJ: October 1989).
²⁹U.S. Environmental Protection Agency, OAQPS, Compilation of Air Pollutant Emission Factors,
Supplement A, (Research Triangle Park, NC: October 1986).
³Hittman, Op. Cit.
19
³¹Based on emission of 2 pounds per MMBtu from coal units today (scrubbed plus uncontrolled), 1
pound per MMBtu from oil units, and no SO₂ from natural gas units. SO₂ emissions from existing coal
units assumed to decline by 4.3 million tons per year by 1995.
³²American Gas Association, Identification of Errors in Science Concepts, Inc. Greenhouse Paper,
Issue Brief 1989-13 (Arlington, VA: August 25, 1989).
³³U.S. Department of Energy, Office of Fossil Energy, Americas Clean Coal Commitment,
(Washington, DC: February 1987) p. A-4.
³⁴U.S. Department of Energy and U.S. Environmental Protection Agency, Energy/Environment Fact
Book, (Washington, DC: March 1978) p. 24.
AGA
American Gas
Association
Energy
Analysis
1515 Wilson Boulevard
A.G.A. Planning & Analysis Group
Arlington, Virginia 22209
EA 1991-2
January 30, 1991
PROJECTED NATURAL GAS DEMAND FROM VEHICLES UNDER THE
MOBILE SOURCE PROVISIONS OF THE CLEAN AIR ACT AMENDMENTS
A.
Introduction
The Clean Air Act Amendments of 1990 are one of the most far-reaching
environmental initiatives ever passed in this country. These amendments contain a
number of sections germane to the natural gas industry, in particular, the mobile
source, acid rain and ozone non-attainment provisions.
The mobile source program has three major components or tiers. First,
conventional gasoline and diesel-powered vehicles sold throughout the U.S. will face
tougher emissions standards starting in 1994. Second, in the country's nine
smoggiest cities, all conventional gasoline will be replaced by reformulated gasoline.
Third and most important to the gas industry, there is a program to promote the
use of clean vehicular fuels as an alternative to gasoline. There is a federal
program that mandates that fleets in 22 urban areas purchase clean fuel vehicles, in
addition to an ambitious pilot program in California. Urban buses will also be
required to be much cleaner. If buses can't be adequately cleaned with an
unproven particulate trap and lower sulfur diesel fuel, they too will be subject to a
stringent clean-fuel program.
The purpose of this analysis is to estimate the incremental demand for natural
gas attributable to the mobile source provisions of the legislation.
B.
Executive Summary
This analysis projects that the incremental demand for natural gas directly
attributable to the mobile source provisions of the Clean Air Act Amendments of
1990 will reach 600 billion cubic feet (Bcf) by 2005 in a Base Case, and 300-1,000
Bcf in Low and High Cases, respectively (see Exhibit 1).
© 1991 by the American Gas Association.
-2-
Exhibit 2 illustrates how many clean fuel vehicles will be purchased and
put in service between 1995 and 2005 as a result of the Clean Air Act fleet
program and the California pilot program, based on A.G.A. projections. It
includes all clean-fuel vehicles regardless of fuel type -- methanol, ethanol,
propane, electricity, natural gas or whatever else can meet the standard.
The minimum level is 4.5 million vehicles in 2005, with a maximum of 9.7
million in that same year.
-
The minimum is based on the estimated number of total purchases
annually in the 22 cities, as required by the law. The maximum
assumes that all non-covered fleets in the U.S. opt-in to the program
on a voluntary basis, in the same manner and at the same rate as
covered fleets.
Natural gas is projected to capture a 75 percent market share in
light-duty and medium-duty fleet trucks in the Base Case. The
projected market share in the Base Case for fleet cars is lower -- 40
percent -- as a result of competition from methanol and
reformulated gasoline. Heavy trucks and buses, which involve far
fewer vehicles, have projected market shares of about 40 to 45
percent, respectively, in the Base Case.
The analysis projects in total just under 4 million natural gas vehicles
(NGVs) purchased by 2005 in the Base Case, with low and high estimates
of 1.8 and 6.7 million vehicles (see Exhibit 3).
Translating these NGVs on the road shown in Exhibit 3 into gas demand
results in totals of 600 Bcf in 2005 in the Base Case, and roughly 300 Bcf
to 1,000 Bcf in the Low and High Cases.
-
These projections assume a 10-year vehicle life; that is, cars
purchased in 1995 will still be on the road in 2005.
There are approximately 195 million vehicles on the road today, consuming
16.3 quadrillion Btu of energy -- almost all of which is gasoline or diesel
fuel. Fleet vehicles account for 6.5 percent of the vehicle population, but
10 percent of total energy consumption (see Exhibit 4). This
high
consumption per vehicle for fleets is one of the chief reasons they are such
an attractive target for NGVs.
The number of natural gas vehicles forecast in this analysis is limited to
those attributable to the Clean Air Act. Natural gas vehicles are currently
penetrating the market on the basis of economics. In addition,
governmental policy initiatives to limit oil imports could rapidly expand this
market. Neither economic nor energy security factors were considered
herein -- just the Clean Air Act.
Exhibit 1
NGV GAS DEMAND FROM CLEAN AIR ACT
1995 - 2005
Bcf
1200
High Case
1000
-3-
800
Base Case
600
400
Low Case
200
0
1995
2000
2005
Exhibit 2
CLEAN FUEL VEHICLES ON THE ROAD
1995 - 2005
Millions of
Vehicles 10
Clean Air Act
Maximum
8
-4-
6
Clean Air Act
Minimum
4
2
0
1995
2000
2005
Exhibit 3
NGVs ON THE ROAD ATTRIBUTABLE TO CLEAN AIR ACT
Millions of
1995 - 2005
Vehicles
7
High Case
6
5
-5-
Base Case
4
3
Low Case
2
1
0
1995
2000
2005
Exhibit 4
1990 VEHICLE POPULATION
Fleets = 13 million (6.5%)
Fleets = 1.7 quads (10%)
-9-
All others
All others
182 million
14.6 quads
195 Million Vehicles
Consume 16.3 Quads
-7-
C.
Background: Legislation
The general structure of the mobile source provisions of the Clean Air Act
Amendments of 1990 is as follows:
1. Areas Covered by the Fleet Program
Twenty-two urban areas are covered by a clean-fuel fleet program.
The program requires that certain fleets, when purchasing new vehicles,
purchase clean fuel vehicles. The program does not target cities per se,
but rather metropolitan statistical areas or consolidated metropolitan
statistical areas, which usually include a number of counties surrounding
the core cities. The total population of these 22 urban areas represents
roughly one-third of the U.S. population.
Twenty-one of the areas are covered because they are in serious,
severe or extreme non-attainment for ozone pollution. The final city is
Denver, which is pulled in because of its severe problem with carbon
monoxide pollution. Although the areas are grouped by their degree of
non-attainment severity, they are all treated equally with respect to the
fleet program.
2. Covered Fleets/Vehicles
"Covered fleets" include those with 10 or more vehicles; capable of
central refueling, excluding various emergency, rental, demos, off-road and
privately-garaged vehicles. It covers weight classes from 0 to 26,000
pounds, from the smallest passenger cars up to furniture-type vans.
3. Phase-In Schedule
In the covered fleets, a minimum percentage of new purchases must
be clean-fuel vehicles (see Exhibit 5). In model-year 1998, 30 percent of
light-duty vehicles -- passenger cars and light vans less than 8,500 pounds --
must be clean-fuel, increasing to 50 percent in model-year 1999, and to 70
percent in 2000 and beyond. For the heavy-duty class, again, including
buses and furniture-type vans from 14,000 to 26,000 pounds, the phase-in
requirement is a constant 50 percent beginning with model-year 1998. A
schedule was not set for the medium and heavier vans from 8,500 to 14,000
pounds -- this will be left up to the states.
4. Credit Program
Fleet operators who purchase more clean-fuel vehicles than
required, or cleaner vehicles than required, or earlier than required, will be
given tradeable credits. These credits may be saved or sold to another
Exhibit 5
FLEET PROGRAM
Percent of
Purchases
PHASE-IN SCHEDULE
100
80
60
-8-
40
70%
20
50%
50% 50%
50%
30%
0
MY 1998
1999
2000 and Beyond
Light Duty
.
Heavy Duty
-9-
fleet with a purchase requirement. For example, assume a fleet is required
to purchase 20 clean fuel vehicles, and that NGVs are twice as clean as the
set standard. The fleet could satisfy its requirement by buying only 10
NGVs. Alternatively, it could buy the 20 NGVs and sell the surplus
vehicle credits to another fleet in the area.
5. California Pilot Program
Clean-fuel passenger and truck vehicle pilot programs will kick-off
in California in model-year 1996 -- two years earlier than the federal fleet
program. The emission standards of the two programs are linked. The
California program, which is limited to vehicles less than 8,500 pounds (a
medium-size van), mandates the production and sale of 150,000 clean-fuel
vehicles per year for model-years 1996 through 1998. For model-years
1999 and beyond, the mandate increases to 300,000 vehicles per year. The
pilot program differs from the federal program in that credits are available
to manufacturers for producing more or cleaner vehicles, not for fleet
owners who purchase these vehicles. To ensure that Detroit would not be
required to manufacture different vehicles for every state, states may
voluntarily opt-in to the program, but only with vehicles that are consistent
with the California program.
D.
Methodology
1.
Minimum Number of Clean-Fuel Vehicles
The first step in this analysis was to estimate the number of fleet vehicles
purchased annually in the U.S., and to determine how many of these vehicles will
be "clean-fuel" (i.e., capable of running on natural gas or some other clean fuel)
based on the requirements set out in Title II of the Clean Air Act Amendments of
1990. This minimum vehicle projection for the years 1995 through 2005 is set out
in detail in Appendix I, and the estimation procedure is described below.
Fleet Cars (Non-California). There are currently 10.6 million fleet cars in the
U.S.¹ Approximately 4.1 million of these vehicles will be covered by the
amendments, after excluding rentals, individually leased cars, emergency
vehicles, etc.¹ It was estimated that 3.3 million of these are capable of central
refueling, assuming central refueling capabilities of 60 to 85 percent,²
depending on the vehicle type. With average turnover periods ranging from 31
to 61¹ months, total U.S. annual purchases are estimated at 1.1 million
vehicles. Based on the population of the affected cities outside of California,³
23 percent of the U.S. population, this translates into annual purchases of
some 258,000 vehicles. The mandatory clean-fuel light-duty vehicle shares of
30 percent in model-year 1998, 50 percent in 1999 and 70 percent in 2000 were
applied to the covered fleet annual purchases of 258,000 to obtain the
estimates shown in Appendix I.
-10-
It should be noted that vehicle projections in all appendices are for the total
number of vehicles on the road -- i.e., vehicles on the road in 2005 are the
cumulative purchases over the 10-year period. Although fleets do not hold
vehicles for 10 years, it is assumed that a resale market will develop for clean-
fuel vehicles, similar to that which now exists for fleet gasoline vehicles.
Fleet Light and Medium Trucks (Non-California). The estimation procedure
for trucks less than 14,000 pounds was similar to that used for fleet cars. Of
the total 2.2 million vehicles currently in the fleet, 2 million vehicles are
covered after excluding exempt vehicles.¹ Based on central refueling
capabilities of 60 to 85 percent, and average turnover periods of 60.5 months,¹
annual purchases of 327,000 light/medium trucks was estimated -- 75,000
purchases per year in the affected cities outside of California, based on
population weighting.
California Pilot Program. The California pilot program requires that 150,000
alternative-fuel cars and light trucks be purchased in model-years 1996 through
1998, increasing to 300,000 in 1999 and thereafter. It was assumed that one-
third of the required total would be satisfied by cars and two-thirds by light
trucks, based on the more favorable economies for alternative-fuel light-duty
trucks relative to cars. It was further assumed that vehicles purchased for the
pilot program would satisfy the federal fleet program requirements in
California.
Heavy-Duty Trucks. There are approximately 1.8 million heavy-duty trucks in
the U.S. less than 26,000 pounds.4 Based on a 10-year vehicle life, this
translates into 180,000 vehicles purchased annually. It was assumed that half
of these vehicles are in fleets greater than 10, and that 80 percent are centrally
refuelable. Applying the population weighting for affected cities and the
mandated 50 percent purchase requirement initiated in model-year 1998
results in estimates of approximately 11,000 clean-fuel heavy-duty trucks
purchased annually.
Urban Buses. Approximately 4,000 urban buses are purchased annually in the
U.S., roughly 60 percent of which go to cities with populations in excess of
750,000.5 Thus, we estimate that some 2,400 clean buses will be purchased
annually in the U.S.
2.
Minimum Alternative Fuel Demand
The fuel demand of the minimum number of clean-fuel vehicles projected is
set out in Appendix II. Both fleet cars and light fleet trucks consume approximately
150 million Btu per year, with fleet cars travelling 27,500 miles per year at 20 to 25
miles per gallon over the forecast period, and light fleet trucks travelling 18,500
miles per year at 14 to 16 miles per gallon. Heavy-duty trucks consume about 170
million Btu per year, or 1,250 gallons, based on an annual requirement of 10,000
-11-
miles per year at 8 miles per gallon. The average urban bus consumes 1,263
million Btu per year -- roughly 9,200 gallons. of diesel fuel.6
3.
Maximum Clean Fuel Vehicles and Fuel Demand
Appendix III shows the estimated maximum number of clean fuel vehicles
attributable to Title II, and Appendix IV indicates the annual fuel demand of these
vehicles. Appendices I and II assume that only fleets in serious, severe and extreme
non-attainment areas purchase clean-fuel vehicles, as required by the legislation.
The maximums in Appendices II and IV assume that all fleets in the U.S.
voluntarily opt-in to the federal program at the same rate and on the same schedule
as those covered fleets in the 22 cities. Some states have already announced that
they intend to opt-in, and others will surely follow as clean-fuel vehicles will provide
one of the best options available to escape the various sanctions that could be
placed on areas which fail to achieve attainment.
4.
NGVs on the Road
Appendices V, VI and VII set out the Low Case, Base Case and High Case
projections for natural gas vehicles on the road attributable to Title II. These
projections were made based on the following market shares applied to the
previously discussed estimate for all clean-fuel vehicle purchases:
Projected NGV Market Shares
Low Case
Base Case
High Case
Fleet Cars
30%
40%
60%
Fleet Light/Med Trucks
50%
75%
85%
Fleet Heavy Trucks
10%
40%
70%
Urban Buses
10%
45%
80%
Light and medium-duty trucks and vans are expected to be the most attractive
market for NGVs, based on their operating characteristics and greater space
available for fuel cylinders. The fleet car market shares are modestly lower than
those for light and medium trucks due to less fuel storage space and anticipated
greater competition from reformulated gasoline, methanol and other alternatives.
Heavy duty truck and urban bus shares for natural gas range from very low to very
high. It is unclear whether mechanical modifications, such as particulate traps for
buses, will prove viable options for meeting the mandates of the legislation. If they
are not, natural gas will capture the lion's share of these markets.
-12-
5.
Gas Demand for NGVs
The gas demand from the NGVs attributable to the Clean Air Act
Amendments -- Low Case, Base Case and High Case -- are presented in
Appendices VIII, IX and X. These consumption levels are based on the same per-
vehicle requirements described above -- 150 MMBtu per year for fleet cars and
light trucks, 170 MMBtu per year for heavy duty trucks, and 1,263 MMBtu per year
for urban buses.
&
-13-
,
Footnotes
1 Bobit Publishing Company, 1990 Automotive Fleet Fact Book, Vol. 29 supplement,
(Redondo Beach, CA: 1990).
2 Runzheimer International, Survey and Analysis of Business Car Policies and Costs,
1989-1990, (Northbrook, IL: 1989). Survey results modified by A.G.A. based on 1989
phone survey to reflect legislation intent to target vehicles "capable of central
refueling" not just those that are centrally refueled.
3 U.S. Bureau of the Census, U.S. Statistical Abstract, 1989, (Washington, DC: 1990).
4 U.S. Bureau of the Census, Truck Inventory and Use Survey, (Washington, DC:
August 1990).
5
American Public Transit Association, 1990 Operating and Financial Statistics,
(Washington, DC: November 1990), and A.G.A. phone discussion with APTA,
December 1989.
6
U.S. Department of Transportation, National Transportation Statistics, (Washington,
DC: July 1990).
APPENDIX I
Minimum Clean Fuel Fleet Vehicles on the Road Due to Clean Air Act
1995-2005
(Thousands)
Fleet Cars
Light/Medium Trucks
California
Non-California
Total
California
Non-California
Total
Heavy Duty Trucks
Urban Buses
Total
1995
15
-
15
30
-
30
-
-
45
1996
65
-
65
130
-
130
-
-
195
1997
115
25
140
230
7
237
3
.7
380
1998
180
120
300
365
35
400
14
1.4
715
1999
280
285
565
565
78
643
25
2.6
1,236
-14-
2000
380
465
845
765
131
896
36
4.3
1,781
2001
480
645
1,125
965
184
1,149
47
6.7
2,328
2002
580
825
1,405
1,165
237
1,402
58
9.1
2,874
2003
680
1,005
1,685
1,365
290
1,655
69
11.5
3,420
2004
780
1,185
1,965
1,565
343
1,908
80
13.9
3,967
2005
880
1,365
2,245
1,765
396
2,161
91
16.3
4,513
APPENDIX II
Minimum Fuel Demand of Clean Fuel Fleet Vehicles Attributable to Clean Air Act
1995-2005
(Bcf-Equivalent)¹
Fleet Cars
Light/Medium Trucks
California
Non-California
Total
California
Non-California
Total
Heavy Duty Trucks
Urban Buses
Total
1995
2.2
-
2.2
4.5
-
4.5
-
-
6.7
1996
9.8
-
9.8
19.5
-
19.5
-
-
29.3
1997
17.2
3.8
21.0
34.5
1.0
35.5
.5
.9
57.9
1998
27.0
18.0
45.0
54.8
5.2
60.0
2.4
1.8
109.2
1999
42.0
42.8
84.8
84.8
11.7
96.5
4.2
3.3
188.8
-15-
2000
57.0
69.8
126.8
114.8
19.6
134.4
6.1
5.4
272.7
2001
72.0
96.8
168.8
144.8
27.6
172.4
8.0
8.5
357.7
2002
87.0
123.8
210.8
174.8
35.6
210.4
10.0
11.5
442.7
2003
102.0
150.8
252.8
204.8
43.5
248.3
11.7
14.5
527.3
2004
117.0
177.8
294.8
234.8
51.4
286.2
13.6
17.6
612.2
2005
132.0
204.8
336.8
264.8
59.4
324.2
15.5
20.6
697.1
¹One Bcf equals approximately 1.03 trillion Btu.
APPENDIX III
Maximum Clean Fuel Fleet Vehicles on the Road Due to Clean Air Act
1995-2005
(Thousands)
Fleet Cars
Light/Medium Trucks
California
Non-California
Total
California
Non-California
Total
Heavy Duty Trucks
Urban Buses
Total
1995
15
-
15
30
-
30
-
-
45
1996
65
-
65
130
-
130
-
-
195
1997
115
85
200
230
28
258
12
1.2
471
1998
180
450
630
365
135
500
48
2.4
1,180
1999
280
1,015
1,295
565
300
865
84
4.4
2,248
2000
380
1,714
2,094
765
504
1,269
120
-16-
7.2
3,490
2001
480
2,413
2,893
965
708
1,673
156
11.2
4,733
2002
580
3,111
3,691
1,165
911
2,076
192
15.2
5,974
2003
680
3,810
4,490
1,365
1,115
2,480
228
19.2
7,217
2004
780
4,509
5,289
1,565
1,319
2,884
264
23.2
8,460
2005
880
5,207
6,087
1,765
1,523
3,288
300
27.2
9,702
APPENDIX IV
Maximum Fuel Demand of Clean Fuel Fleet Vehicles Attributable to Clean Air Act
1995-2005
(Bcf-Equivalent)¹
Fleet Cars
Light/Medium Trucks
California
Non-California
Total
California
Non-California
Total
Heavy Duty Trucks
Urban Buses
Total
1995
2.2
-
2.2
4.5
-
4.5
-
-
6.7
1996
9.8
-
9.8
19.5
-
19.5
-
-
29.3
1997
17.2
12.8
30.0
34.5
4.2
38.7
.5
.9
70.1
1998
27.0
67.5
94.5
54.8
20.2
75.
2.4
1.8
173.7
1999
42.0
152.2
194.2
84.8
45.0
129.8
4.2
3.3
331.5
2000
57.0
257.1
314.1
114.8
75.6
190.4
6.1
5.4
516.0
-17-
2001
72.0
362.0
434.0
144.8
106.2
251.0
8.0
8.5
701.5
2002
87.0
466.6
553.6
174.8
136.6
311.4
10.0
11.5
886.5
2003
102.0
571.5
673.5
204.8
167.2
372.0
11.7
14.5
1,071.7
2004
117.0
676.4
793.4
234.8
197.8
432.6
13.6
17.6
1,257.2
2005
132.0
781.0
913.0
264.8
228.4
493.2
15.5
20.6
1,442.3
¹One Bcf equals approximately 1.03 trillion Btu.
APPENDIX V
NGVs on the Road Due to Clean Air Act--Low Case
1995-2005
(Thousands)
Fleet
Light/
Heavy
Urban
Total
Cars
Medium
Duty
Buses
Trucks
Trucks
1995
4.5
15.0
-
-
19.5
1996
19.5
65.0
-
-
84.5
1997
42.0
118.5
.3
0.1
160.9
1998
90.0
200.0
1.4
0.1
291.5
1999
169.5
321.5
2.5
0.4
493.8
-18-
2000
253.5
448.0
3.6
0.5
705.5
2001
337.5
574.5
4.7
0.9
917.4
2002
421.5
701.0
5.8
1.1
1,129.2
2003
505.5
827.5
6.9
1.5
1,341.1
2004
589.5
954.0
8.0
1.8
1,552.9
2005
673.51
1,080.5
9.1
2.0
1,764.7
APPENDIX VI
NGVs on the Road Due to Clean Air Act--Base Case
1995-2005
(Thousands)
Fleet
Light/
Heavy
Urban
Total
Cars
Medium
Duty
Buses
Trucks
Trucks
1995
6
23
-
-
29
1996
26
98
-
-
124
1997
68
186
4
-
258
1998
186
338
8
1
533
1999
372
416
31
2
821
-19-
2000
588
812
44
3
1,447
2001
804
1,058
57
5
1,924
2002
1,019
1,304
70
6
2,399
2003
1,235
1,551
83
8
2,877
2004
1,451
1,797
97
10
3,355
2005
1,666
2,043
110
12
3,831
APPENDIX VII
NGVs on the Road Due to Clean Air Act--High Case
1995-2005
(Thousands)
Fleet
Light/
Heavy
Urban
Total
Cars
Medium
Duty
Buses
Trucks
Trucks
1995
9
26
-
-
35
1996
39
110
-
-
149
1997
120
219
8
1
348
1998
378
425
34
2
839
1999
777
735
59
4
1,575
2000
-20-
1,256
1,079
84
6
2,425
2001
1,736
1,422
109
9
3,276
2002
2,215
1,765
134
12
4,126
2003
2,694
2,108
160
15
4,977
2004
3,173
2,451
185
19
5,828
2005
3,652
2,795
210
22
6,679
APPENDIX VIII
Gas Demand from NGVs Attributable to Clean Air Act--High Case
1995-2005
(Bcf)
Fleet
Light/
Heavy
Urban
Total
Cars
Medium
Duty
Buses
Trucks
Trucks
1995
1.4
4.0
-
-
5.4
1996
5.8.
16.5
-
-
22.3
1997
18.0
32.8
1.4
1.3
53.5
1998
56.7
63.8
5.8
2.5
128.8
1999
116.6
110.2
10.0
5.1
241.9
-21-
2000
188.4
161.8
14.3
7.6
372.1
001
260.4
213.3
18.5
11.4
503.6
2002
332.2
264.8
22.8
15.2
635.0
2003
404.1
316.2
27.2
19.0
766.5
2004
476.0
367.6
31.4
24.0
899.0
2005
547.8
419.2
35.7
27.8
1,030.5
APPENDIX IX
Gas Demand from NGVs Attributable to Clean Air Act--Base Case
1995-2005
(Bcf)
Fleet
Light/
Heavy
Urban
Total
Cars
Medium
Duty
Buses
Trucks
Trucks
1995
0.9
3.4
-
-
4.3
1996
3.9
14.7
-
-
18.6
1997
10.2
27.9
0.7
-
38.8
1998
27.9
50.7
1.4
1.3
81.3
1999
55.8
62.4
5.3
2.5
126.0
2000
88.2
121.8
-22-
7.5
3.8
221.3
2001
120.6
158.7
9.7
6.3
295.3
2002
152.9
195.6
11.9
7.6
368.0
2003
185.2
232.6
14.1
10.1
442.0
2004
217.6
270.0
16.5
12.6
516.7
2005
250.0
306.4
18.7
15.2
590.3
APPENDIX X
Gas Demand from NGVs Attributable to Clean Air Act--Low Case
1995-2005
(Bcf)
Fleet
Light/
Heavy
Urban
Total
Cars
Medium
Duty
Buses
Trucks
Trucks
1995
0.7
2.2
-
-
2.9
1996
2.9
9.8
-
-
12.7
1997
6.3
17.8
0.1
0.1
24.3
1998
13.5
30.0
0.2
0.1
43.8
1999
25.4
48.2
0.4
0.4
74.4
-23-
2000
38.0
67.2
0.6
0.5
106.3
2001
50.6
86.2
0.8
0.9
138.5
2002
63.2
105.2
1.0
1.1
170.5
2003
75.8
124.1
1.2
1.5
202.6
2004
88.4
143.1
1.4
1.8
234.7
2005
101.0
162.1
1.5
2.0
266.6
AGA
American Gas
Association
Energy
Analysis
1515 Wilson Boulevard
A.G.A. Planning & Analysis Group
Arlington, Virginia 22209
EA 1991-1
January 30, 1991
PROJECTED NATURAL GAS DEMAND FOR ACID RAIN CONTROL
A.
Introduction
The Clean Air Act Amendments of 1990 are one of the most far-reaching
environmental initiatives ever passed in this country. These amendments contain a
number of sections germane to the natural gas industry, in particular, the acid rain,
mobile source and ozone non-attainment provisions.
The purpose of the acid rain provisions is to reduce the emissions of sulfur
dioxide (SO₂) and nitrogen oxides (NOₓ) from electricity generating plants by
roughly 10 million and 2 million tons per year, respectively. The amendments do
not specify how these reductions are to be achieved. Rather, plants affected are
free to choose from a wide array of compliance options -- e.g., switching to natural
gas or lower-sulfur coal, scrubbing, retiring plants or purchasing reductions achieved
at some other unaffected plant.
The purpose of this analysis is to estimate the incremental demand for natural
gas attributable to the acid rain provisions of the amendments. A plant-by-plant
analysis was completed for each of the 110 plants affected by Phase I. A more
general analysis was conducted for Phase II, which takes effect in January 2000.
B.
Executive Summary
This analysis projects that the incremental demand for natural gas attributable
to the acid rain provisions will reach just over 1 trillion cubic feet per year by 2005
in the Base Case. High and Low Case estimates were also made, forming a range
from 650 billion cubic feet to 1.5 trillion cubic feet in 2005 (see Exhibit 1). The
Base Case results are summarized below.
© 1991 by the American Gas Association.
Exhibit 1
INCREMENTAL GAS DEMAND FOR ACID RAIN CONTROL
Bcf
1995 - 2005
1600
High Case
1400
1200
Base Case
1000
-2-
800
Low Case
600
400
200
0
1995
2000
2005
-3-
Phase I
110 Plants -- The 110 large plants affected in Phase I (1995-2000) are
projected to have a demand increase for natural gas of 510 billion cubic
feet (Bcf) per year for acid rain compliance (see Exhibit 2).
-
This 510 Bcf is attributable to roughly one-fourth of the affected
units, contributing about 11 percent of the total Phase I SO₂
reduction.
Scrubbers are expected to provide 50 to 60 percent of the Phase I
reduction, and low sulfur coal some 30 to 40 percent.
-
Natural gas will be particularly attractive in older units and those
with more modest reduction requirements, as well as those that
would face difficulty in retrofitting scrubbers or changing coal
sources.
Phase II
The total Phase II demand increase for natural gas is estimated to reach 1,030
Bcf by 2005, just over double the Phase I level.
110 Plants -- The gas demand for the 110 large Phase I plants is projected
to drop from 510 to 230 Bcf annually in Phase II, as the SO₂ reduction
limit drops from 2.5 to 1.2 pounds per MMBtu.
Other Existing Plants -- The gas focus will shift in Phase II to those coal
and high-sulfur oil units emitting over 1.2 pounds of SO₂ per MMBtu. An
annual demand of 530 Bcf is projected for these 400 or so plants, which
tend to be smaller and/or cleaner than the 110 Phase I plants.
470 Bcf is attributable to coal-fired plants not in the group of 110.
Gas is projected to account for 20 percent of this group's required
SO₂ reduction.
-
An additional 60 Bcf of gas demand is projected for high-sulfur oil
units, which will satisfy 40 percent of the reduction mandate for
these plants.
New Plants -- New generating plants will turn increasingly to gas after the
year 2000 because of the absolute SO₂ cap of 8.9 million tons. New coal or
oil units brought on line after the cap is in place will have to obtain SO₂
offsets equivalent to their incremental SO₂ emissions. Gas units will not
require offsets, and a demand increase of 270 Bcf per year by 2005 is
projected for these plants.
Exhibit 2
Projected Incremental Natural Gas Demand
Attributable to Acid Rain Provisions
Bcf
of Clean Air Act - Base Case
Total
Demand
1000
New Plants
500
Other Existing Plants
110 Large Existing Plants
1995
2000
2005
Phase I
Phase II
-5-
It should be noted that the gas used to comply with the acid rain provisions may
or may not be consumed at the affected unit. An affected coal-fired electric power
plant could substitute gas for coal on-site, or it could obtain its SO₂ reduction from
some other plant on the electric utility system. In fact, because of the liberal
trading provisions in the amendments, the reduction could even be acquired from
an industrial source converting from high sulfur oil to gas and opting into the
program.
C.
Background
The general structure of the acid rain provisions of the Clean Air Act
Amendments of 1990 is as follows. In Phase I -- January 1, 1995 until January 1,
2000 -- 110 electric utility generating units, each above 100 megawatts and emitting
more than 2.5 pounds of SO₂ per MMBtu, must reduce their SO₂ emission rate to
2.5 pounds per MMBtu. In Phase II the program is expanded to include all units
above 25 megawatts, and the emission rate limit is reduced to 1.2 pounds of SO2
per MMBtu. In addition, after January 1, 2000, new electric utility plants and
cogeneration units above 25 megawatts that come on line must not cause the total
emissions of this sector to exceed an absolute cap of 8.9 million tons. Thus, if a
new coal- or oil-fired plant will emit 25,000 tons of SO₂ per year, the plant owner is
responsible for reducing emissions by 25,000 tons per year at some other site. The
reduction could be obtained at some other plant on the same system, or it could be
obtained at an unrelated electric utility or industrial plant and purchased by the
responsible plant operator.
The most attractive features of the acid rain provisions from a natural gas
industry perspective are that: (1) there is no restriction on how SO₂ reductions are
achieved; (2) reduction allowances may be purchased, sold and traded; and (3) non-
affected plants, both industrial and electric utility, may opt-in to the program. For
example, a large industrial plant burning high-sulfur fuel oil in New York state
could convert to natural gas and sell the reduction to an affected utility plant in
some other state. This flexibility greatly enhances the value of natural gas, much of
which is already consumed at dual-fuel capable facilities. It also provides affected
plants with a significant source of SO₂ reductions which will be very competitive
from an economic perspective. For example, most analysts would consider the
addition of a scrubber that provides SO₂ reductions at a cost of $250 per ton to be
very economical. At this level of $250 per ton of SO₂ removed, the incremental
value of gas, when switching from 1.5 pounds per MMBtu fuel oil, is 20 cents per
MMBtu, and, when switching from 5 pounds per MMBtu coal, the incremental
value of gas is over 60 cents per MMBtu.
This trading possibility is often overlooked by analysts attempting to project the
volumes of gas that will be required for acid rain control, and thus their projections
tend to be low. In fact, the extremely flexible nature of the legislation makes it
very difficult to determine exactly how electric utilities will comply. However, the
outlook for natural gas is very favorable because: (1) natural gas emits virtually no
-6-
SO₂; (2) most gas is consumed at dual-fuel capable industrial and electric utility
plants, which currently switch on the basis of swings of pennies per MMBtu, (3) an
active trading market is anticipated with no geographic boundaries, and (4) the 8.9
million ton cap greatly enhances the value of gas as a fuel for new generating
facilities, as well as an "offset" fuel in existing facilities to allow future growth.
D.
Methodology
1. Phase I
An analysis of each of the 110 affected Phase I plants and its compliance
options was performed. Most of the variables considered in this analysis are
presented in Appendices A and B, and discussed below.
Identification. Each of the 110 affected plants, and the state in which it is
located, is listed in column 1 of Appendix A. The affected generating units at
the plants are listed in column 2 - not all units at the 110 plants are affected.
Allowances. An allowance is essentially a permit to emit one ton of SO2. The
Phase I allowances, as provided in the legislation, are set out in column 3 of
Appendix A.
Capacity. Column 4 of Appendix A indicates the size of the affected units in
megawatts. Smaller units will be more likely to switch fuels for compliance -- to
natural gas or low-sulfur coal -- due to the significant diseconomies of scale
associated with scrubbing.
Age. The installation date of the affected units is provided in column 5 of
Appendix A. Older units -- those built in the mid-1960s or earlier -- will be
less likely candidates for the major engineering modifications required for
scrubbers, and, to a lesser extent, changes in coal type.
Retrofit Potential. As indicated in column 6 of Appendix A, retrofitting
scrubbers at existing plants can range from being relatively easy to virtually
impossible. At some sites, scrubbers are precluded due to space limitations or
other engineering factors. These sites are thus logical candidates to use natural
gas or low-sulfur coal for compliance.
Boiler Type. Due to the differing combustion characteristics of high sulfur and
low-sulfur coal, changing the coal feed of wet bottom or cyclone boilers is
undesirable. These boiler types, indicated in column 7 of Appendix A, are
more likely to use natural gas or scrubbers.
Gas Capability. The last column of Appendix A indicates whether the affected
plant is on a utility system that includes gas-burning equipment -- steam or gas
turbines. If the capacity of these units is large enough, additional gas could
-7-
easily be substituted for higher-sulfur fuels in the fuel mix. Also, adding gas-
burning capability on these systems would be easier, as some gas delivery
capability already exists.
Coal Transport. Those plants supplied with coal via barge or rail would be
more likely to shift to western low-sulfur coal than those supplied via conveyor
or truck. The coal transport mode is indicated in column 3 of Appendix B.
Coal Source. Column 4 of Appendix B lists the state of origin of each plant's
coal supply. Political or state regulatory pressure may limit the ability of plants
using local high-sulfur coal to shift to out-of-state lower-sulfur coal, thus making
gas co-firing and scrubbing more attractive.
Coal Contract. Mine-mouth generating stations or those receiving high-sulfur
coal from company-owned mines or long-term contracts will be less likely to
shift their coal source. These plants, indicated in column 5 of Appendix B, will
be more likely to install scrubbers or use natural gas for compliance.
Fuel Input. The annual fuel input of the affected units is presented in column 6
of Appendix B. This estimate is based on the capacity of the unit, a 33 percent
boiler efficiency and a 70 percent annual capacity utilization.
Emission Rate. Column 7 of Appendix B indicates the 1989 SO₂ emission rate
of the affected units. In Phase I, this rate must be reduced to roughly 2.5
pounds per MMBtu. Units relatively close to this target will be more likely to
use gas, while those far off will be less inclined to do so.
Gas Required. Columns 8 and 9 of Appendix B indicate the proportion of the
fuel mix that would have to be natural gas, assuming the 1989 emission rate for
the remainder of the mix, to meet the limits of 2.5 and 1.2 pounds per MMBtu
of Phases I and II, respectively. It should be noted that this proportion could
be lowered if gas were used in conjunction with some other strategy, such as
additional coal cleaning or using a lower-sulfur, but non-compliance, coal.
The above factors, along with others not presented in the appendices, were
considered in determining the likely compliance strategies of the 110 Phase I plants.
For example, a small or moderately sized mine-mouth cyclone unit needing a 20
percent SO₂ reduction and having existing gas-fired boilers on the system would be
a good candidate for gas substitution. A 1,200 megawatt unit burning 7 pounds-per-
MMBtu coal with an easy scrubber retrofit factor would not.
One critical factor to consider is whether there is an easy or moderate difficulty
scrubber retrofit on the system as opposed to the particular plant. Scrubbers at one
large plant may provide excess allowances that could be used by smaller plants on
the same system that can't scrub.
-8-
Results. The Phase I reduction requirement for the 110 plants is
approximately 4.3 million tons of SO2. This analysis indicates that using 510 Bcf
of gas annually could satisfy the reduction requirements of about one-fourth of
the affected units, contributing roughly 11 percent of the 110 plants' required
SO₂ reduction -- 500,000 tons annually. The other 89 percent, or 3.8 million
tons, would come from scrubbing or switching to low-sulfur coal. (It should be
noted that when gas is substituted for oil, whether at the affected plant or via a
trade, the quantity of gas required for the offset will be larger than if gas were
substituted for coal, since oil-to-gas substitutions generally remove less SO₂ than
coal-to-gas substitution.)
2. Phase II
In Phase II, affected plants will essentially be required to reduce their average
emission rate to 1.2 pounds per MMBtu -- less than half the Phase I rate. This
stringent cap would require a 70 to 80 percent gas substitution level for most of the
110 Phase I plants. Thus, it is projected that a smaller proportion of plants will use
gas for compliance in Phase II, decreasing the gas used at these sites from 510 to
230 Bcf per year. The 10 years prior to the outset of Phase II will be used to install
scrubbers at a more manageable pace, and to allow old coal contracts to terminate
so that newer contracts for lower-sulfur coals can be executed.
The gas focus in Phase II will shift from the 110 largest plants to roughly 400
smaller existing plants that will also be affected. Coal plants (outside of the 110)
will be required to emit no more than 1.2 pounds per MMBtu, resulting in an
emission reduction of some 1.5 to 2.0 million tons of SO₂ per year. An analysis as
detailed as that done for the 110 plants was not performed on these smaller plants.
Rather, it was assumed that the share of the tonnage reduction provided by gas
would increase from 11 percent in Phase I to roughly 20 percent in Phase II for
these smaller and/or cleaner units. These units are more attractive gas candidates
because they are smaller will require a lesser percentage reduction than most
Phase I plants, and scrubbing them would be far more costly. Scrubbers are
expected to produce 50 to 60 percent of the Phase I 110-plant reduction, but only
about 10 percent of the reduction from the smaller Phase II coal units. In contrast,
the low-sulfur coal share is anticipated to increase from about 30 or 40 percent to
roughly 70 percent.
Of the 360,000-ton SO₂ reduction projected attributable to gas for the smaller
coal plants, 80 percent is projected to result from oil-to-gas substitution and 20
percent from coal-to-gas substitution. Again, this gas substitution for the higher-
sulfur fuels could take place at the affected units or at other units that subsequently
transfer them to the affected units. The annual gas demand at these plants is
projected at 470 Bcf.
High-sulfur oil plants will also be affected in Phase II. About 1,600 trillion Btu
of oil is currently consumed by electric utilities annually, and about one-fourth of
-9-
this oil exceeds the 1.2 pound per MMBtu Phase II limit. A total SO₂ reduction of
some 160,000 tons per year will be required of these plants -- 40 percent of which is
assumed to be satisfied with gas, the remainder by switching to lower-sulfur oil.
These plants, many of which already have both gas- and oil-burning capability, are
projected to demand an additional 60 Bcf per year for acid rain compliance.
The final category of plants that will demand additional gas for acid rain
compliance in Phase II is new electricity generating units -- including both
cogenerators and electric utility plants. There is an absolute cap of 8.9 million tons
of SO₂ per year for generating plants in 2000 and beyond. Generating units that
come on line post-2000 and that produce SO₂ must reduce an equivalent amount of
SO₂ at some other site. Thus, there will be a strong preference for gas to fuel these
units, since gas emits no SO₂.
It is estimated that an additional 5 percent of the utility and non-utility
(cogenerators and independent power producers) units will be gas-fired as a result
of the legislation. (Most analysts projected that the market share for gas would be
very high in these markets -- 35 to 70 percent -- even without the clean air
legislation.) This translates into an additional 270 Bcf per year by 2005, based on
projected capacity additions of 5,000 megawatts per year for cogenerators and
10,000 megawatts per year for utility plants.
In aggregate, the total incremental gas demand in 2005 from the 110 Phase I
plants, the smaller Phase II coal and oil plants, and the new generating units is
projected to be 1,030 Bcf per year.
3. High and Low Case Assumptions
Natural gas provides 11 percent of the required SO₂ reduction in Phase I. This
increases to 13 percent in the High Case, and reduces to 7.5 percent in the Low
Case, resulting in a Phase I range of 350 to 600 Bcf per year.
The Phase II decline in gas demand at the 110 plants is 25 percent more severe
in the Low Case and 50 percent less severe in the High Case. Whereas gas satisfies
20 percent of the required SO₂ reduction in the Base Case for small coal-fired units
in Phase II, it satisfies 10 and 30 percent in the Low and High Cases, respectively.
Similarly, the 40 percent contribution of gas in small oil-fired units is reduced to 20
percent in the Low Case and increased to 50 percent in the High Case. The
incremental 5 percent market share in the electricity generation market in Phase II
is reduced to 4 percent in the Low Case and increased to 7 percent in the High
Case. The range in the year 2005 as a result of these modifications is 650 to 1,500
Bcf per year.
Characteristics of Affected Phase I Electric Utility Power Plants -- A
Phase I
Scrubber
Gas-Burning
State
Allowances
Capacity
Installation
Retrofit
Capability
Plant¹
Unit¹
(Tons/Yr)¹
(Summer, Megawatts²
Date²
.
Potential²
Boiler Type2
On System³
Alabama
Colbert
1-4
59,690
776
1955
VD
-
GT
5
37,180
496
1965
E
-
GT
EC Gaston
1-4
74,230
1,044
1960-62
VD
-
ST
5
59,840
887
1974
D
-
ST
Florida
Big Bend
1-3
82,250
1,079
1970-76
M
W
-
Crist
6-7
50,880
809
1970-73
M
-
ST
Georgia
Bowen
1-4
254,580
3,009
1971-75
E
-
ST,GT
Hammond
1-3
26,910
300
1954-55
D
-
ST,GT
4
37,640
459
1970
M
-
ST,GT
McDonough
1-2
40,510
507
1964
D
-
ST,GT
Wansley
1-2
136,200
1,747
1976-78
E
-
ST,GT
Yates
1-5
39,520
574
1950-58
D
-
ST,GT
6-7
46,240
682
1974
E
-
ST,GT
Illinois
Baldwin
1-3
128,980
1,761
1970-75
M
C
ST,GT
Coffeen
1-2
47,460
840
1965-72
E
C
GT
Grand Tower
4
5,910
103
1958
VD
-
GT
Hennepin
2
18,410
224
1957
D
-
ST,GT
Joppa Steam
1-6
69,030
1,014
1953-55
M
-
-
Kincaid
1-2
65,340
1,108
1967-68
M
C
ST,GT
Meredosia
3
13,890
180
1960
VD
-
GT
Vermilion
2
8,880
107
1956
D
-
ST,GT
Indiana
Bailly
7-8
26,810
490
1962-68
D
C
ST,GT
Breed
1
18,500
380
1960
E
NA
-
Cayuga
1-2
67,500
985
1970-72
M
-
-
Clifty Creek
1-6
100,830
1,215
1955-56
D
W
-
EW Stout
5-6
28,010
212
1958-61
VD
-
-
7
23,610
439
1973
E
-
1
FB Culley
2-3
21,260
351
1966-73
VD
-
GT
FE Ratts
1-2
16,810
230
1968
M
-
I
A-1
Phase
Scrubber
Gas-Burning
State
Allowances
Capacity
Installation
Retrofit
Capability
Plant¹
Unit¹
(Tons/Yr)1
(Summer, Megawatts²
Date²
Potential²
Boiler Type2
On System3
Indiana
Gibson
1-4
162,810
2,540
1975-79
E
-
-
Pritchard
6
5,770
99
1956
NA
NA
-
Michigan City
12
23,310
468
1974
D
C
ST,GT
Petersburg
1-2
48,810
700
1967-69
M
-
-
Gallagher
1-4
27,950
560
1958-61
D
-
-
Tanners Creek
4
24,820
500
1964
D
C
-
Wabash River
1-5
14,280
435
1953-56
VD
-
-
6
12,280
318
1958
D
-
-
Warrick
4
26,980
300
1970
D
-
GT
Iowa
Burlington
1
10,710
207
1968
NA
NA
-
Des Moines
7
2,320
119
1964
NA
NA
ST,GT
George Neal
1
1,290
130
1964
NA
NA
ST,GT
ML Kapp
2
13,800
217
1967
D
-
ST
Prairie Creek
4
8,180
139
1967
NA
NA
ST
Riverside
5
3,990
130
1961
NA
NA
ST,GT
Kansas
Quindaro
2
4,220
145
1971
D
C
ST
Kentucky
Coleman
1-3
36,430
450
1969-71
M
-
-
Cooper
1-2
22,770
336
1965-69
VD
-
-
EW Brown
1-2
18,020
271
1957-63
VD
-
GT
3
26,100
394
1971
M
-
GT
Elmer Smith
1-2
20,930
399
1964-74
VD
C
-
Ghent
1
28,410
522
1974
D
-
GT
Green River
4
7,820
109
1959
NA
NA
GT
HL Spurlock
1
22,780
300
1977
NA
NA
-
Henderson II
1-2
25,650
300
1973
D
W
-
Paradise
3
59,170
1,046
1970
E
C
GT
Shawnee
10
10,170
147
1953
NA
NA
GT
Maryland
Chalk Point
1-2
46,240
660
1964-65
M
-
ST
CP Crane
1-2
19,560
376
1961-62
NA
NA
ST,GT
Morgantown
1-2
73,740
1,163
1970-71
E
-
ST
A-2
Phase
Scrubber
State
Gas-Burning
Allowances
Capacity
Installation
Retrofit
Plant1
Unit¹
Capability
(Tons/Yr)1
(Summer, Megawatts²
Date²
Potential²
Boiler Type2
Michigan
On System³
JH Cambell
1-2
42,340
583
1962-67
M
-
GT
Minnesota
High Bridge
6
4,270
179
1959
NA
NA
ST,GT
Mississippi
Jack Watson
4
17,910
260
1968
D
-
ST,GT
5
36,700
502
1973
E
-
Missouri
ST,GT
Asbury
1
16,190
200
1970
M
C
-
James River
5
4,850
90
1970
NA
NA
Labadie
ST,GT
1-4
154,070
2,216
1970-73
D
-
Montrose
ST,GT
1-3
25,680
450
1958-64
VD
-
ST
New Madrid
1-2
60,720
1,200
1972-77
M
C
-
Sibley
3
15,580
353
1969
M
C
GT
Sioux
1-2
46,260
900
1967-68
M
C
Thomas Hill
ST,GT
1-2
29,640
483
1965-69
M
C
-
New Hampshire
Merrimack
1-2
32,190
357
1960-68
D
C
GT
New Jersey
BL England
1-2
20,780
289
1962-64
VD
C
New York
ST,GT
Dunkirk
3-4
26,660
375
1959-60
VD
-
Greenidge
ST,GT
4
7,540
104
1953
VD
-
-
Milliken
1-2
23,580
308
1955-58
VD
-
-
Northport
1-3
70,400
1,137
1958-60
NA
NA
Port Jefferson
ST,GT
3-4
22,800
388
1968-72
NA
NA
Ohio
ST,GT
Ashtabula
5
16,740
243
1958
VD
-
-
Avon Lake
8
11,650
230
1959
VD
-
-
9
30,480
634
1970
D
-
-
Cardinal
1-2
72,590
1,170
1967-68
D
C
-
Conesville
1-3
14,600
391
1959-62
VD
C
-
4
48,770
733
1973
E
C
-
Eastlake
1-4
40,970
637
1953-56
VD
-
-
5
34,070
445
1972
D
-
I
A-3
Phase I
Scrubber
State
Gas-Burning
Allowances
Capacity
Installation
Retrofit
Plant¹
Unit¹
Capability
(Tons/Yr)1
(Summer, Megawatts²
Date²
Potential²
Boiler Type2
On System³
Ohio
Edgewater
4
5,050
103
1957
NA
NA
-
JM Gavin
1-2
159,640
2,600
1974-75
E
-
-
Kyger Creek
1-5
93,200
1,019
1955
M
W
-
Miami Fort
5-6
12,140
243
1949-60
D
-
GT
7
38,510
500
1975
M
-
GT
Muskingum River
1-4
54,780
790
1953-58
D
c
-
5
40,470
575
1968
E
C
-
Niles
1-2
16,040
228
1954
VD
C
-
Picway
5
4,930
95
1955
NA
NA
-
RE Burger
3-5
29,360
402
1950-55
D
-
-
WH Sammis
5-6
64,100
900
1967-69
VD
-
-
7
43,220
600
1971
D
8
-
WC Beckjord
5-6
31,970
653
1962-69
D
-
GT
Pennsylvania
Armstrong
1-2
29,840
349
1958-59
VD
-
-
Brunner Island
1-2
58,860
699
1961-65
M
-
-
3
53,820
730
1969
E
-
-
Cheswick
1
39,170
562
1970
M
-
ST
Conemaugh
1-2
126,240
1,702
1970-71
E
-
GT
Hatfields Ferry
1-3
115,420
1,500
1969-71
E
-
-
Martins Creek
1-2
25,480
280
1954-56
NA
NA
-
Portland
1-2
16,170
401
1958-62
D
-
GT
Shawville
1-4
48,930
606
1954-60
VD
-
GT
Sunburey
3-4
20,210
222
1951-53
VD
-
-
Tennessee
Allen
1-3
47,760
873
1965
D
C
GT
Cumberland
1-2
181,540
2,550
1973
E
-
GT
Gallatin
1-4
76,460
1,080
1956-59
D
-
GT
Johnsonville
1-10
80,670
1,304
1951-59
VD
-
GT
West Virginia
Albright
3
12,000
137
1954
VD
-
-
Fort Martin
1-2
82,790
1,110
1967-68
D
-
-
Harrison
1-3
136,270
1,920
1972-74
M
-
-
Kammer
1-3
55,590
600
1958-59
VD
C
-
Mitchell
1-2
89,490
1,460
1971
VD
-
-
A-4
Mount Storm
1-3
121,730
1,574
1965-73
E
Phase I
Scrubber
State
Gas-Burning
Allowances
Capacity
Installation
Retrofit
Plant¹
Unit1
Capability
(Tons/Yr)1
(Summer, Megawatts²
Date²
Potential²
Boiler Type2
Wisconsin
On System³
Edgewater
4
24,750
334
1969
VD
C
ST,GT
La Crosse/Genoa
3
22,700
345
1969
VD
-
-
Nelson Dewey
1-2
12,690
211
1959-62
D
C
N. Oak Creek
ST,GT
1-4
22,050
430
1953-57
VD
-
GT
Pulliam
8
7,510
123
1964
D
-
S. Oak Creek
ST,GT
5-8
53,680
1,057
1960-68
VD
-
GT
Abbreviations:
NA - Data not available
E
- Easy scrubber retrofit, 1.0 to 1.3 times capital cost of FGD at new 500 MW unit.
M
- Moderate scrubber retrofit, 1.3 to 1.6 times capital cost of FGD at new 500 MW unit.
D
- Difficult scrubber retrofit, 1.6 to 1.9 times capital cost of FGD at new 500 MW unit.
VD - Very difficult scrubber retrofit, more than 1.9 times capital cost of FGD at new 500 MW unit.
C
- Cyclone
W - Wet bottom
ST - Steam boiler
GT - Gas turbine
Sources:
1
U.S. House of Representatives, Clean Air Act Amendments of 1990, Conference Report to accompany S.1630, (Washington, DC: U.S. GPO,
October 26, 1990) pp. 208-213.
2
Energy Ventures Analysis, Inc., for the U.S. Environmental Protection Agency, Evaluation of SO2, Emissions and the FGD Retrofit Feasibility
at the 200 Top Emitting Generating Stations, (Washington, DC: January 10, 1986).
3
U.S. Department of Energy, Energy Information Administration, Inventory of Power Plants in the United States - 1989, (Washington, DC:
U.S. GPO, September 1990).
A-5
Characteristics of Affected Phase I Electric Utility Power Plants -- B
Coal Supply²
Percent Gas Required⁵
1989 Emission
State
Transport
Favorable
Fuel Input
Rate
Plant¹
Unit¹
Mode
Origin
Contract
(TBtu/yr)3
(#SO₂/MMBtu)⁴
Phase I
Phase II
Alabama
Colbert
1-4
B
OH
-
48
3.89
36
69
5
B
OH
-
31
3.89
36
69
EC Gaston
1-4
C,R
AL
X
65
3.32
25
64
5
C,R
AL
X
55
3.32
25
64
Florida
Big Bend
1-3
B
WKY
-
67
3.55
30
67
Crist
6-7
B
IL,WKY
-
50
4.63
46
74
Georgia
Bowen
1-4
R
EKY,WKY
X
188
2.29
-
48
Hammond
1-3
R
EKY,VA
-
18
2.91
14
59
4
R
EKY,VA
-
28
2.91
14
59
McDonough
1-2
R
IL,WKY
-
31
4.34
42
72
Wansley
1-2
R
IL,IN
-
109
4.43
44
73
Yates
1-5
R
IL,AL
-
36
3.61
31
67
6-7
R
IL,AL
-
42
3.61
31
67
Illinois
Baldwin
1-3
R
IL
X
110
5.31
53
78
Coffen
1-2
R
IL
X
52
6.88
64
83
Grand Tower
4
R
IL
-
6
5.11
51
77
Hennepin
2
B
IL
X
14
5.26
52
78
Joppa Steam
1-6
R,B
IL,WKY
-
63
3.35
25
64
Kincaid
1-2
C
IL
X
69
6.74
63
83
Meredosia
3
B,T
IL
-
11
4.53
45
74
Vermilion
2
T
IL,IN
-
7
4.20
40
71
Indiana
Bailly
7-8
R
IL
X
30
4.85
48
75
Breed
1
NA
NA
NA
23
7.11
65
83
Cayuga
1-2
R
IN
-
61
4.04
38
70
Clifty Creek
1-6
B
WKY,IN
-
76
5.95
58
80
EW Stout
5-6
R
IN
-
13
3.26
23
63
7
R
IN
-
27
3.26
23
63
FB Culley
2-3
T
IN
I
22
5.46
54
78
B-1
Coal Supply²
Percent Gas Required⁵
1989 Emission
State
Transport
Favorable
Fuel Input
Rate
Plant¹
Unit¹
Mode
Origin
Contract
(TBtu/yr)3
(#SO₂/MMBtu)⁴
Phase I
Phase II
FE Ratts
1-2
T
IN
-
14
5.27
53
77
Gibson
1-4
R
IL,IN
X
159
4.48
44
73
Pritchard
6
NA
NA
NA
6
3.50
29
66
Michigan City
12
R
IL
-
29
4.14
40
71
Petersburg
1-2
R,T
IN
X
44
4.16
40
71
Gallagher
1-4
B
IN
-
35
4.24
41
72
Tanners Creek
4
B
WKY,NWV
-
31
3.08
19
61
Wabash River
1-5
R
IN
-
27
3.88
36
69
6
R
IN
-
19
3.88
36
69
Warrick
4
R
IN
X
18
5.71
56
79
Iowa
Burlington
1
NA
IL,IN,KY
NA
13
4.94
49
76
Des Moines
7
NA
NA
NA
7
NA
NA
NA
George Neal
1
NA
WY
NA
8
.95
-
-
ML Kapp
2
B
IL,MT
-
13
5.25
52
77
Prairie Creek
4
NA
IL,IN
NA
8
4.57
45
74
Riverside
5
NA
IL
NA
8
3.35
25
64
Kansas
Quindaro
2
R
IL
-
9
2.58
3
53
Kentucky
Coleman
1-3
B
IN,WKY
-
28
4.26
41
72
Cooper
1-2
T,R
EKY
-
21
2.40
-
50
EW Brown
1-2
R,T
EKY,TN
-
17
3.55
30
66
3
R,T
EKY,TN
-
24
3.55
30
66
Elmer Smith
1-2
T
WKY,IN
-
25
5.37
53
78
Ghent
1
B
IN,EKY
X
32
2.58
3
53
Green River
4
NA
NA
NA
6
3.86
35
69
HL Spurlock
1
NA
NA
NA
18
1.78
-
33
Henderson II
1-2
B
IN,WKY
-
18
NA
NA
NA
Paradise
3
C,B,T
WKY
X
65
8.36
70
86
Shawnee
10
NA
NA
NA
9
1.92
-
37
Maryland
Chalk Point
1-2
R
PA,MD
-
41
2.85
9
-
I
B-2
Coal Supply²
Percent Gas Required⁵
1989 Emission
State
Transport
Favorable
Fuel Input
Rate
Plant¹
Unit¹
Mode
Origin
Contract
(TBtu/yr)3
(#SO₂/MMBtu)⁴
Phase I
Phase II
Maryland
CP Crane
1-2
NA
NA
NA
23
3.14
20
62
Morgantown
1-2
R
PA,MD
-
72
2.90
14
59
Michigan
JH Cambell
1-2
R,B
OH,EKY
-
36
1.18
-
-
Minnesota
High Bridge
6
NA
NA
NA
11
.57
-
-
Mississippi
Jack Watson
4
B
AL,WKY
-
16
3.87
35
69
5
B
AL,WKY
-
31
3.87
35
69
Missouri
Asbury
1
C
MO,KS
X
13
9.32
73.
87
James River
5
NA
NA
NA
6
4.11
39
71
Labadie
1-4
R
IL
X
139
4.53
45
74
Montrose
1-3
T,R
MO,OK
X
28
.83
-
-
New Madrid
1-2
B
IL
-
75
5.77
57
79
Sibley
3
R
IL
-
22
5.60
55
79
Sioux
1-2
R
IL,WY
X
56
3.24
23
63
Thomas Hill
1-2
T
MO,IL
X
30
7.77
68
85
New Hampshire
Merrimack
1-2
R
NWV
-
22
3.05
18
60
New Jersey
BL England
1-2
R
NWV
-
18
3.87
35
70
New York
Dunkirk
3-4
R,T
PA
-
23
3.19
22
62
Greenidge
4
R,T
PA
-
6
3.11
20
61
Milliken
1-2
R,T
PA
-
19
2.76
9
57
Northport
1-3
WA
NA
NA
71
1.0
-
-
Port Jefferson
3-4
WA
NA
NA
24
1.0
-
-
Ohio
Ashtabula
5
R
QH,PA
-
15
4.97
50
76
Avon Lake
8
R
OH
-
14
3.86
35
69
9
R
OH
-
39
3.86
35
69
Cardinal
1-2
B,R,T
OH,SWV
X
73
3.79
34
68
B-3
Coal Supply²
Percent Gas Required⁵
1989 Emission
State
Transport
Favorable
Fuel Input
Rate
Plant¹
Unit1
Mode
Origin
Contract
(TBtu/yr)3
(#SO₂/MMBtu)⁴
Phase I
Phase II
Ohio
Conesville
1-3
C,T
OH
X
24
5.34
53
78
4
C,T
OH
X
46
5.34
53
78
Eastlake
1-4
R
OH
-
39
4.88
49
75
5
R
OH
-
27
4.88
49
75
Edgewater
4
NA
NA
NA
6
3.84
35
69
JM Gavin
1-2
C,R,B
OH
X
163
5.74
56
79
Kyger Creek
1-5
B
NWV,OH
-
63
6.36
61
81
Miami Fort
5-6
B
SWV,OH
-
15
2.84
12
58
7
B
SWV,OH
-
31
2.84
12
58
Muskingum River
1-4
C
OH
X
49
7.67
67
84
5
C
OH
X
36
7.67
67
84
Niles
1-2
T
OH,PA
-
14
5.42
54
78
Picway
5
NA
NA
NA
6
4.99
50
76
RE Burger
3-5
B
OH
-
25
4.97
50
76
WH Sammis
5-6
B
OH,PA
-
56
2.85
12
58
7
B
OH,PA
-
37
2.85
12
58
WC Beckjord
5-6
B
OH,EKY
-
40
2.94
15
59
Pennsylvania
Armstrong
1-2
T
PA
-
21
2.97
16
60
Brunner Island
1-2
R
PA
X
43
2.78
10
57
3
R
PA
X
45
2.78
10
57
Cheswick
1
B
PA
X
35
2.50
-
52
Conemaugh
1-2
C,T,R
PA
X
106
3.35
25
64
Hatfields Ferry
1-3
B
NWV,PA
X
94
3.31
24
64
Martins Creek
1-2
NA
NA
NA
17
3.14
20
62
Portland
1-2
R
PA,NWV
-
25
2.82
11
57
Shawville
1-4
T
PA
-
38
3.19
22
62
Sunburey
3-4
R,T
PA
-
13
3.65
32
67
Tennessee
Allen
1-3
B
WKY
-
54
3.59
30
67
Cumberland
1-2
B
WKY
X
160
4.80
48
75
Gallatin
1-4
B,R
WKY
-
67
4.56
45
74
Johnsonville
1-10
B
IN,WKY
-
81
2.94
15
59
B-4
Coal Supply²
Percent Gas Required⁵
1989 Emission
State
Transport
Favorable
Fuel Input
Rate
Plant¹
Unit¹
Mode
Origin
Contract
(TBtu/yr)3
(#SO₂/MMBtu)⁴
Phase I
Phase II
West Virginia
Albright
3
T
NWV
-
9
2.61
4
54
Fort Martin
1-2
B
NWV,EKY
-
69
2.81
11
57
Harrison
1-3
C,R,T
NWV
X
120
4.66
46
74
Kammer
1-3
C
NWV
X
37
6.89
64
83
Mitchell
1-2
R,B
NWV
X
91
2.06
-
42
Mount Storm
1-3
C,R,T
NWV
X
98
2.91
14
59
Wisconsin
Edgewater
4
R
IL,IN
-
20
2.50
-
52
La Crosse/Genoa
3
B
IL,MT
0.
21
3.78
34
68
Nelson Dewey
1-2
B
IL,IN
-
13
1.57
-
24
N. Oak Creek
1-4
R,B
WKY,IL
-
26
2.64
5
55
Pulliam
8
B
WKY,IN
-
8
3.54
29
66
S. Oak Creek
5-8
R,B
WKY,IL
-
66
2.64
5
55
Abbreviations:
NA - Data not available
B - Barge
R
- Rail
T - Truck
C - Conveyor
Sources:
1
U.S. House of Representatives, Clean Air Act of 1990, Conference Report to accompany S.1630, (Washington, DC: U.S. GPO, October 26,
1990) pp. 208-213.
2
Energy Ventures Analysis, Inc. for the U.S. Environmental Protection Agency, Evaluation of SO₂ Emissions and the FGD Retrofit Feasibility
at the 200 Top Emitting Generating Stations, (Washington, DC: January 10, 1986).
3
Calculated on the basis of 70 percent annual capacity utilization and 33 percent boiler efficiency.
4
National Coal Association, Steam Electric Plant Factors - 1990, (Washington, DC: 1990).
5
Calculated on the basis of percent of gas required in fuel mix to reduce SO₂ emission rate to 2.5 #/MMBtu in Phase I and 1.2 #/MMBtu in
Phase II.
B-5