Record Proceedings:°f Conference on Natural Gas Use State Regulation and Market Dynamics in the Post 636/Energy Policy Act Era

A Conference jointly sponsored by the U.S. Department of Energy and the Xationul Association of Regulatory Utility Commissioners April 26-28, 199} in .We Orleans, Louisiana

tf wtm soy r* on r*cycUd paper TABLE OF CONTENTS

Conference Program 1

List of Registrants 8

Monday. April 26

Bruce Ellsworth 23 Vito Slagliano 27 Bill Rosenberg 38 Peter Bradford 45 Ixn Coburn 49 Michael Baly 53 Chuck Jordan 57 Frank Heintz 64 Mike Reeves 76 Rich Itteilag 86 James Lee 96 Patrick Smith 97 Arlon Tussing 102 Jim McClymond 107 Paul Buckley 116 Steve Furbacher 117 Adam Jaffe 121 James Cannon 125 Norm Bryan 135 Richard Geiss 153 Craig Matthews 159 Branko Terzic 167 R. Gamble Baldwin 170 Karl Rabago 177 Jed Smith 182 Robert Ridgley 194 Lawrence Smith 204 Steve Voorhees 215 Steve Harvey 231 Robert Brown 238 Tuesday. April 27

Ruth Kretschmer 258 Larry Bickle 261 Marge O'Connor 282 Jim Schretter 287 William Johnson 309 Paul Zielinski 330 Dick Farman 334 Bhl Shane 348 Bill Benham 350 Tom Vessels 358 Russ Fleming 478 Larry Hall ". 486 Dave Jones 499 David Webb 509 Jim Mahoney 515 Rod Lemon 527 Margaret Ann Samuels 530 Robert Burns (Academic Forum) 541 Mary Barcella (Academic Forum) 546 Bill Whitsitt 561 Phil Fassett 567 Robert Burns 570 Calvin Manshio 573 Robert Bradley, Jr 581 Andy Merrels 584 Bob Patrylo 590 Minturn Smith 592 Rich Kinder 599 Jacek Makowski 612 Jack King 629 Jim Bowe 638 NARUC-DOE National Conference on Natural Gas Use State Regulation and Market Dynamics in the Post 636/Energy Policy Act Era

SUNDAY, April 25

5:00 p.m.-9:00 p.m. Registration

8:00 p.m.-9:30 p.m. Cocktail Reception -- International Room, Mezzanine Level MONDAY, April 26

7:30 a.m. Registration

7:45 a.in.-8:30 a.m. Coniinemal Breakfast - International Room, Mezzanine Level

8:30 a.m.-10:00 a.m. Plenary Session - International Room, Mezzanine Level Convening the Conference: State Policies in a Post 636/EPACT Era

Panel Chair: Dennis Nagei, Iowa Utilities Board and President, National Association of Regulatory Utility Commissioners (NARUC)

Bruce Ellsworth, New Hampshire Public Utilities Commission and Chair, NARUC Natural Gas Committee Hazel O'Leary, Secretary (remarks to be delivered by Vito Stagliano, Acting Assistant Secretary, Domestic and International Energy Policy) Keynote Address: Senator J. Bennett Johnston (remarks to be delivered by satellite link-up) Bill Rosenberg, President, E3 Ventures, Inc. (former Environmental Protection Agency Assistant Administrator for Clean Air Act Compliance)

10:00 a.m.-10:30 a.m. Coffee Break

10:30 a.m.-12:00 p.m. Plenary Session - International Room, Mezzanine Level

Btu Tax and Its Implications

Panel Chair: Peter Bradford, New York Public Service Commission

Len Coburn, Acting Director, Office of Oil & Natural Gas Policy, U.S. Department of Energy Michael Baly, President, American Gas Association Ed Rothschild, Press Director/Energy Policy Director, Citizen Action Chuck Jordan. Senior Consultant, Cambridge Energy Research Associates 12:00 p.m.-l:30 p.m. -- Imperial Room, Mezzanine Level Lunch

Panel Chair: Ken Malloy, Office of Domestic and International Energy Policy, U.S. Department of Energy Speaker: Frank Heintz, Chairman, Maryland Public Service Commission

1:30 p.m.-3:00 p.m. Concurrent Sessions

Session A — Gold-Rex Room, Mezzanine Level Commercial Markets

Panel Chair: Larry Cobb, North Carolina Utilities Commission

Mike Reeves, Executive VP, Operations, Peoples Gas Light and Coke Company Rich Itteilag, Director of Marketing, Missouri Public Service Co., a division of Utilicorp United James Lee, Executive VP, Columbia Gas Distribution Companies Patrick Smith, Energy Coordinator, Big Bear Stores Company

Session B — International Room, Mezzanine Level PUC Review of Local Distribution Company Management of Supply

Pane! Chair: Leo Reinbold, North Dakota Public Service Commission

Arlon Tussing, President, ARTA Inc. Jini McCIymond, President, Peoples Natural Gas, a division of Utilicorp Paul Buckley, Deputy People's Counsel, Maryland People's Counsel Steve Furbacher, VP and General Manager, Chevron USA Production Co. Adam Jaffe, Professor, Harvard University

Session C ~ Bayou Il-TV Room, Bayou Level Vehicles Markets

Panel Chair: Julius Kearney, Arkansas Public Service Commission

James Cannon, Energy Policy Analyst, New Mexico Energy, Mineral and Natural Resources Department Norm Bryan, VP Marketing, Pacific Gas and Electric Richard Geiss, Executive Engineer, Chrysler Corporation Tom Moore, President and CEO, Natural Fuels Corporation

3:00 p.m.-3:30 p.m. Coffee Break - International Room, Mezzanine Level 3:30 p. m. -5:00 p. m. Concurrent Sessions

Session A - Gold-Rex Room, Mezzanine Level Financial Dimensions to Changing Regulation and Markets

Panel Chair: Steve Fetter, Michigan Public Service Commission

Craig Matthews, CFO and Exec. VP, Brooklyn Union Gas Company Curt Launer, VP, Donaldson, Lufkin, Jenrette Branko Terzic, Commissioner, Federal Energy Regulatory Commission R. Gamble Baldwin, Managing Partner, Natural Gas Partners, L.P.

Session B - International Room, Mezzanine Level IRP, Fuel Switching and Demand Side Management

Panel Chair: Paul Hanaway, Rhode Island Public Utilities Commission

Karl Rabago, Commissioner, Texas Public Utility Commission Jed Smith, Director, Market Planning and Analysis, Washington Gas Light Robert Ridgley, President and CEO, Northwest Natural Gas Company Nick Nichols, National Economic Research Associates

Session C -- Bayou II-IVRoom, Bayou Level National Petroleum Council Study

Panel Chair: Nancy Boyd, Iowa Utilities Board

Larry Smith, VP Production, Shell Oil Company (Chair of NPC Committee that drafted the Report) Mike Morris, COO and Exec. VP, Consumers Power Company Steve Voorhees, Senior VP, SON AT Energy Services Steve Harvey, Managing Consultant, R.J.Rudden Associates Robert Brown, Manager, Natural Gas Marketing, Mobil Oil Corporation

MONDAY EVENING: 6:00 p.m.-7:30 p.m. - Imperial Room, Mezzanine Level Cocktail Reception Sponsored by the Natural Gas Council TUESDAY, April 27

This morning's sessions will be held in the Orpheum Theater, located across the street from the University Place entrance to the Fairmont Hotel.

7:45 a.m.-8:30 a.m. Continental Breakfast - Lobby of Orpheum Ttieater

8:30 a.m.-10:00 a.m. Plenary Session -- Orpheum Theater Capacity Contracting (Resale and New Capacity)

Panel Chair: Ruth Kretschmer, Illinois Commerce Commission

Barney Adams, Executive Direetor, Materials and Fuels, Madison Gas and Electric Co. Ron Mucci, VP Rates and Regulator)' Affairs, Williams Natural Gas Co. Larry Bickle, CEO, Tejas Power Company Marge O'Connor, Senior Counsel, Mobil Oil Coip. Jim Schretter, C.C. Pace Resources

10:00 a.m.-10:30 a.m. Coffee Break

10:30 a.m.-12:00 p.m. Plenary Session -- Orpheum Tlieater Incentive Regulation for LDCs

Panel Chair: Joan Smith, Oregon Public Utility Commission

Ken Gordon, Chairman, Massachusetts Department of Public Utilities Rick Richard, CEO, New Jersey Resources Corp. Bill Johnson, President and CEO, Gas Service, Western Resources Paul Zielinski, Director of Corporate Planning and Regulatory Policy, Rochester Telephone Corp.

12:00 p.m.-1:30 p.m. - International Room, Mezzanine Level Lunch

Panel Chair: Vicky Bailey, Indiana Utility Regulatory Commission Speaker: Dick Farman, CEO of SoCal Gas and Chairman, Natural Gas Council 1:30 p. m. -3:00 p. in. Concurrent Sessions

Session A — University Room, Second Level Upstream Issues

Panel Chair: Richard Frum, West Virginia Public Service Commission

Bill Shane, former Chairman of the Pennsylvania Public Utility Commission Bill Benham, VP Regulatory Affairs, Amoco Production Company Tom Vessels, President, Vessels Oil & Gas Company Russ Fleming, Senior VP, Gas Business Unit, New York State Electric and Gas Larry Hall, President and COO, KN Energy

Session B — Orphcum Theater New End-Use Markets

Pane) Chair: Richard Casad, Washington Utilities and Transportation Commission

Dave Jones, CEO, Atlanta Gas Light Co. and Chairmrn, American Gas Association David Webb. Senior VP, Gas Research Institute Frank Jeffreys, Director of Marketing, Consolidated Natural Gas Jim Mahoney, VP and Director of Fuel Supply, New England Power

Session C -- Bayou 11-1V Room, Bayou Level Residential Markets

Panel Chair: Keith Bissell, Tennessee Public Service Commission

Rod Lemon, Chairman of Dept. of Political Economy, Monmouth College Rick Morrow, Manager of Core Markets, SoCal Gas Company Chuck Guinn, Deputy Commissioner for Policy and Planning, New York State Energy Office Margaret Ann Samuels, Chair of Gas Committee, National Association of State Utility Advocates (Ohio Office of Consumers' Counsel)

Session D - Mayor's Chamber, Second Level Academic Forum

This is an open forum for academics and policy analysts to discuss their ongoing research and to become better informed as to developments and opportunities affecting the academic community. There will be no pre-planned speakers.

3:00 p.m.-3:30 p.m. Coffee Break -- Lobby of Orpheum Theater 3:30 p.m.-5:00 p.m. Concurrent Sessions

Session A - Orpheum Tfieater Environmental Regulation

Panel Chair: Rose McKinney-James, Nevada Public Service Commission

Steve Reynolds, CEO, Pacific Gas Transmission Corp. Bill Whitsitt, VP for Marketing and Public Affairs, Oryx Energy Co. Phil Fassett, Manager, Business Analysis, ALCOA Marika Tatsutani, Resource Specialist, Natural Resources Defense Council

Session B -- Bayou II-FV Room, Bayou Level Institutional and Procedural Issues

Panel Chair: Mike Biddison, Ohio Public Utilities Commission

James Cawley, LeBoeuf Lamb Leiby and MacRae and former Pennsylvania Commissioner Robert Bums, Nationnl Regulatory Research Institute Cal Manshio, former Illinois Commerce Commissioner Laura Murrell, VP Regulatory, Tenneco Gas Marketing and former Chair of the Kentucky Public Service Commission

Session C - University Room, Second Level Industrial Markets

Panel Chair: Scott Neitzel, Wisconsin Public Service Commission

Rob Bradley, President, Institute for Energy Research Andy Merrels, former Director of Energy Purchases, Owens Corning Fiberglas Robert Patrylo, Senior VP, Niagara Mohawk Power Corp Mintum Smith, Manager, Energy Affairs, Procter and Gamble Paper Products Company WEDNESDAY, April 28

7:45 a.m.-8:30 a.m. Continental Breakfast - International Room, Mezzanine Level

8:30 a.m.-10:00 a.m. Plenary Session - International Room, Mezzanine Level Electric Generation

Panel Chair: Nancy Norling, Delaware Public Service Commission

Richard Kinder, President and COO, Enron Jacek Makowski, Chairman and CEO, J. Makowski Assoc, Inc. Jack King, President and COO, Entergy Enterprises, Inc. Jim Bowe, Partner, Hunton and Williams

10:00 a.m.-10:30 a.m. Coffee Break

10:30 a.m.-12:00 p.m. Plenary Session - International Room, Mezzanine Level State Commissioners' Reaction

Panel Chair: Bruce Ellsworth, New Hampshire Public Utilities Commission

Pat Perkins, Missouri Public Service Commission Jo Ann Kelly, Nevada Public Service Commission Bud Pardini, Washington Utilities and Transportatioii Commission S. Peter Bickley, New Mexico Public Service Commission

12:00 p.m. Plenary Session - International Room, Mezzanine Level Adjournment of the Conference Paae: 06/23/93 HMUC-DOE K»tlcnal Conftrcnet on «atural Sas U»» Mm Orleans, Louisiana April 26-28, 1993

Principal Rigistrant Title Organization Address City State Zipcode

Ackenmn, Sue Northwest Nat Gas 220 NV Second Avenue Pcrtlarej OR 97209 Adam, Barney Exec Olr, Hatrt/Fuel Hiidsw Gas £ Elec 133 South Blair Street P.O. Box 1231 ttadixon Ui 53701 Adams, Jack Attorney Clarke-Hobll Cas P.O. Box 608 Jackson Al 365*5 Adams, WilHcm 0. utility Adtin I Iowa Utilities Board '.ueas State Office Bldg. Oes Maine* IA 50319 Adger, John Consultant Liberty Consulting 250 U. Prate is;eet Suite 2201 Baltiasre W 21201

Albergo, Michael Marketing Manager Michael aaker Jr Inc 4301 Dutch Ridge goad leaver PA 15009 Aldrich, Stephen Oir, Business Dvlpat Canbridge Energy 20 University Road Charles Sepitre MA 021JB Allday, Hartin Dir, Regulatory Afrs Coastal Corporation 9 Greenwey Ploza Houston IX 77054 All red, Alan K. Director, Rates Mountain Fuel Supply 180 East 1st South '.o.4 lane City UT A4139 Alper, Ron Staff Attornev Maryland PSC 231 E. Baltimore Street Baltiecre HD 21202

Alward, Jonice Staff Attorney Arizona CC 1200 West Washington Fhoenix AZ 85007 Anderson, R. Keith Vice President OEDC K00 Woodloch Forest Drive Suite 520 The Uoodlends IX 77380 Anderson, Robert Economist Bomeville Pur Admin P.O. Box 3621 Pert I End OR 97203 Andrews, Ben Director, Utilities Town of Smyrna, TN 315 South Lowry Street Smyrna 37167 Ansari, H.J. Petroleum Specialist World Bank 1818 H Street, H.U. Washington 20433 Har, Plonnins Spprt Florida Power & Lght 9250 U. Ftaller Street Miami FL 33144 Arigonl, Susan Capacity Manager Pub Serv Co of CO 1225 17th Street Suite 1103 Denver CO 80202 Armenti, Cam».n J. Coninissiooer Neu .ersey BRC Two Gateway Center Keuark HJ 07104 Arnriak, Michael J. AVP-State Reg Sets MX Pipeline 500 Renaissance Center Detroit Ml 46243 Arthur, Warren Coonlssioner South Carolina PSC Post Office Drawer 11649 Coluefcia SC 29211 Austin, Tom Hgr, Regulatory f.frt Chevron U.S.A. P.O. Box 2100 Houston TX 77252 Bah, Hawah Pub Utils Specialist Dlst of Colunblo PSC 450 5th Street, N.U. Washington CC 20001 Bailey, Vicky A. Connissioner Indiana URC Indiana Gov't Ctr S., Ste E3&6 302 w. Wsshjtn Indianapolis IN 46204 Baker, Chris Spvsr, Mktg Service* Laclede Gss Coapany 720 Olive Street St. louis HO 63101 Saker, Georgette J. Counsel MidCon Corporation 701 East 22nd Street Loatwrd U 60148 Baldwin, R. Datable Managing Partner Natural Gas partners 115 East Putnaa Avenue 2rd Fleer Sreenuich CT 06S30 Baly, III, Michael President Aacrican Gas A*sn 1515 Uilsen Boulevard Arlington VA 22209 Barcella, Mary Consulting Economist 2944 Davenport Street, N.W. Uaihlngton DC 20003 Barn, Sergio Manager Pctrabrat America 1330 Avenue cf the Aaericas 16th floor Hew York NT 11553 Bartels, Michael G. Sr. Vice President East Ohio Gw Co 1717 East Ninth Street P.O. Box 5759 Cleveland OH 44101-0759

Bashaw, Frank Hgr, Regulatory Affr Talisaan Energy 855 2nd Street, S.U. Suite 2400 Calgary, Atbt CAN T2P 449 Battaglfa, Tia SVP, Reg Counsel Access Energy Corp 655 Metro Place South Suite 303 Dublin OH 43017 Seatl, iCeith Assistant Deputy IN Util Cnsmr Cnslr N501 100 N. Senate Indianapolis IN 46204 Benham, Uilliaa T. Vice President Aaoco Production Co 200 E. Randolph Drive Chicago IL 60680-06S9 Bennett, Porter President Bentek 621 17th Street #2055 Denver CO 80293 Berg, Thomas F. Policy Analyst Wash Int1I Energy 1155 21st Street, N.U. Suite 202 Washington DC 20036 Bergstron, Barry VP, Administration earnest Gas Supply 12S5 West Pender street Vancouver, B.C. CAN V6E 4B1 Sickle, Larry U. Chairman and CEO Tejas Power Corp 200 West lake Park Boulevard Suite #1000 Houston TX 77079 Buckley, S, Peter Commissioner New Mexico PSC 224 E. Palace Avenue Marian Hall Santa Fe KM 87501 aiddison, J. Michael Comtissioner Ohio PUC 180 East Broad St. Coluabus OH 43266 Bissell, Keith Ccmnissioner Tennessee PSC 460 Ja Robertson Pkwy. Nashville TH 37243

O OO •«•*> 2 04/23/93 MMC-DOE Mtional Confaraua on Mtura' Cas I Mm Orlwns, Louisiana April Z6-M, 1993

Principal Registrant Title Organization Address City Stata Zlpeodt

Bonanza, Joseph f. VP and Treasurer Boston Cas Coapany One Petcoo Street Eoston NA C210S lohlcn. Edward Asst Atty General Kasa Atty General 131 Treannt Street 3rd Floor Soston MA 02114 looth, Robert Hgr, Cai/Vater sect Arkansas PSC P.O. Box 400 little Sock AR 72203-0400 3ora>, Ken Presfdeit BCS, Inc. 5550 Sterrett Place Suite 216 Golu*la 21044

Boston, Roy Hgr, Stite Relations MldCon Corporation 701 F. ?2iti Stre«< Loifcerd K 60148 Bout, jln Partner Hunton I Will Ism 2000 Pennsylvania Avenue, N.U. Washington DC 20006 Boyd, Nancy S. CcanUsioner loua Utilities Board Lucas State Office Blrig. 0es Kolnss IA 50319 Bradford, Peter M. Chat mi New York PSC Three Enpire State Plaza Albany MY 12223 Bradley, Robert ;, . President Irst for Engy Resch 6219 olympia Houston IX 77057

Brttdshaw, Junle L. Natural Gas Supply 1129 20th Street, H.u. Suite JCO Washington DC 20036 Branch, Debbie J. President Vesta Energy Co 400 Oneok Plaza 100 V. 5th St. TuUs OK 74103 Bramelly, Kevin H. Director of Rates Massachusetts DPI) 100 Cortjridge Street Bcston HA 02202 Bratcafolis, Jeanne Solicitor Elizabethtown Gas Co One Elizabethtoun Plfiza P.O. Bex 3175 Union MJ 07083-1975 8roy, Hike VP-Corp Reg Affairs Panhandle Eastern 5400 Westhcimer Court Houston TX 77056

Bridge, Tracy Dir, Rates & Tariffs Hinnesasco 201 S. 7th Strc-;t HN 55402 Brodsky, Lorry Vice President Illinois Power Co 500 South 27th Street Oecotur 1L 62525 Brogon, Susarme Harytond PSC 231 East Baltimore Street Baltinore KD 21202 Broun, Robsrt L. Mgr, Mat Car, Hrktg Kobil Oil Corpcny 3225 Gal Iowa Road foirfnx VA 22037 Brown, jr., Thoaas J. Oir, Regulatory Htrs Colutfcia Gas of Ohio 200 Civic Center Dr. Colu^us OH 43216

Bryan, Horran I. VP, Marketing Pacific Gat X Elec P.O. Box 7700DB $zn Francisco CA 94177 Buckley, AI on Rates - Gas Progran Washington UTC P.O. Sox 47250 O'.yrpia WA 98504-7250 Buckley, Paul S. Deputy People's Coun HD People's Counsel 231 E. Baltimore St., 9th Fir tacriean Bttjg. ealtioore W) 21202 Burch, Sarena Attorney SC Pipeline Corp P.O. 3ox 102407 Colirbia SC 29224-2407 Burns, Janes Hgr, Business Dvlpnt Great Uest Energy 1800 - 321 Sixth Avenue, S.I/. Calgary, Albt CAN 72P 3R2

Burra, Linda H. Reg Affairs Manager T«xaco P.O. Box 4700 Houston TX 77210-4700 Burns, Robert Sr Research Spec. NRR1 1080 CarnO* Road Suite 560A Columbus OH 43210 fiusch, Jlai Consul twit, Reg Mr* ABOCO Production Co P.O. Box 3092 Houston TX 77253 Bush, Nick President Natural Gas Supply 1129 20th Street, N.U. Suite J00 Washington DC 20036 Butcher, Angela Energy Policy Anlyst Michigan PSC 6545 Mercantile Way Lansing MI 48909

Callaghan, Susan Exec Adaln Assistant Tennessee PSC 460 Janet Robertson Pkwy. Nashville TH 37243 Cameron, Lori Executive Director The Energy Council 222 U. Lea Coifnas Boulevard Suite 1913 Irving TX 75039 Caaeron, Terry VP, Pub/Econ Affairs foothills Pipe Lines 3100, 707 - 8th Avenue, S.u. Calgary, Albt CAM T2P 3U8 Campbell, Donna Senior Gas Analyst Arkansas PSC 1000 Center Street Little Dock AR 72291 Cannon, Gordon Sr. Marketing Rep Norcen Marketing 700 Larkspui' Landing Circle "uite 199 Larkspur CA 94939

Cannon, Janes Energy Policy Anlyst MM Engy-Hnrl-Nat Res 2040 S. Pacheco Street Santa Fe KM 87505 Cano, Craig S. Associate Editor Inside FERC 1120 Vermont Ave. ";jite 1200 Washington DC 20005 Capello, Cheryl Staff Louisiana PSC P.O. Box 91154 Baton Rouge LA 70821 Carlson, Curt Dir, Dallas Supp off US DOE 1420 U. Mockingbird Lane Tuite 400 Dallas TX 75247 Casad, Richard 0. Cosnissioner Washington UTC 1300 S. Evergreen Park Dr.. SW Clvrpie UA 98504

Cathcart, Dave Coord, Econ Studies Centra Gas Ontario 200 Yorklano" inulevard North York, Ont CAN M2J 5C4 Caudill, Hark D. Dir, Regulatory Affr Atlanta Gas Light Co P.O. Box 4S69 Atlanta GA 30302-4569 Cawley, Jaaes H. _. Partner LeSoeuf Imb leiby 320 Market Street, Strbry Sq Suite E400 Harrisburg PA 17101 Cencini, Richard ~ Director, Reg Affrs Bay State Gas Co 300 Friberg Parkuoy Wettborough MA 01581-5039 Chaabers, Patrick^ Senior Vice Pres. Orange and Rocklsnd One Blue Hill Plaza Pearl River HY 1096S Page: 06/25/93 HARUC-OOE National Conference on Natural Gas Use New Orleans, Louiniina tprU 26-28, 1593

Principal Registrant Title Organization Address City State Zipcode

Cheatham, Jack SVP £ General Courts I WCM 555 13th St., NW Suite SOD west Washington DC 20004 Chicoine, frank VP, Hrktg/Gas Supply Valley Resources lS^i Mendon Boad Ctrfcerlend Rl 02864 Christian, Ron Indiana Gas Conpany 16.''! N. Meridian Street IN 46202-1496 Clork, Jcrroll Executive Director Arkansas PSC P.O. Box 400 Little Rock AR 72203-0400 Clement, Daniel G. Hcgulotory Sec Head Southern Cat Gas 633 W. Fifth Strict Suite 540'j Los Angeles CA 90071 Cot*, Laurence A. Conniosioner North Carolina W. Post Office Box 29510 NC 27626 Coburn, Leonard Actg Dir, Oil/Hat Gs US 0OE 1000 Independence Avenue, S-U. Washington DC 20858 Cochrane, Anna Ofr, Gov't Relations MidCon Corporation 1747 Pennsylvania Avenue, H.W. Suite 300 Washington DC 20006 Collins, Mary A. Dir, pub Relations Planmetrics, Inc. 8600 West Bryn Kawr Avenue Suite WO Korth Chicego II 60631 Cannes, G. Alan Associate Lawrence Berkeley Lb Building 90, Rooco 4G00 1 Cyclotron Rd Berkeley CA 94720

Cooper, Jesr> Executive VP Rocky Htn Oi I & Gas 1775 Sherman Stre-t Suite 2501 Denver CO 80203 Cooper, Trevor Sr. Marketing Rep ProGas Limited #4100, 400 Third Avenue, S.u. Calgary, Albt CAN T2P 4ff2 Corbon, Frederick L. Commissioner Indiana use 913 State Office Bldg. ]nd;£r.3pot is IN 46204 Ccrley, Kinterley «. Termeco Gas P.O. Box 3511 Houston TX 77252 Corwell, Steve Dir, Gas Sply/Reg Af Central R Light Co 300 liberty Street Pecria IL 61602 Cory, John President Gaslantic 109 East Jerrettsville Road Forest Hill MD 21050 Cotter, William Conmissioner New tork PSC Three Empire State Plaza Albany NY 12223 Covino, Susan General Counsel KCS Energy Marketing 379 Thornall Street Edison •!J 08837 Cowan, William J. General Counsel Hew York DPS 3 Empire State Plaza Albany NY 12223 Crane, Leslie Hearing Examiner Delaware PSC P.O. Box 457 Dover DE 19903 Crane, Robert f. VP, Gas Business Oev ConEdison 4 Irving Place New York NY 10003 Csajko, Roger A. Dir, Regulatory Rels Brooklyn Union Gas One HetroTech Center Brooklyn NY t:201 Cuccinelli, Ken VP, Market ing/Tchngy Consolidated Nat Gas 625 Liberty Street Pittsburgh PA 15222 Cunnings, Charles J. Dir, Regulatory Afrs Wisconsin Gas 626 East Wisconsin Avenue UI 53202 Cunningham, Todd H. Associate Editor EEI Washington llr 701 Pennsylvania Avenue, N.U. Washington DC 20004 Curron, Patricia Attorney/Consultant Curren, Corbett 800 Geusner Suite 930 Houston TX 77024 Curtis, Gene Dir-Hatural Gas Div North Carolina UC P.O. 6 IK 29520 Raleigh NC 27626-0520 Curtis, Thomas H.I. Dir, Energy Research Pegasus Econometrics 47 Ketisrk Street Hoboken NJ 07030 O'Atessandro, Oavid Morrison 1 Hecker 1747 Pennsylvania Avenue Suite 200 Washington DC 20006 Dal ton, Robert Engineer Entergy Services P.O. Box 8082 Little Rock AR 72203 Daly, Kip Director, Gas Supply Consumers Power Co 1945 West Parnall Road JscUton Ml 49201 Oando, (Cathy Regulatory Affairs Chevron Production P.O. Box 2100 Houston TX 77252 Davis, Gary Dir, Corporate com Iroquois Gas Trnsosn One Corporate Drive Suite 606 Shetton CT 06484 Davis, Jin Hgr, Gas Operations Central 1L Pub Serv 607 East Adams Springfield 62739 Oavis, Karima Manager American Gas Assn 1515 Wilson Boulevard Arlington a 22209 VA Davis, Kin Gas I Water Amlyst Arkansas PSC P.O. Box 400 Little Rock AR 72203-0400 Dawe, George Account Manager Algonquin Gas Trnstns 1284 Soldiers Field Road Boston MA 02135 Dayton, Ken SFO Petro Expiretn P.O. Box 681 Eufaul* OK 74432 Deason, J. Terry Comissfoner Florid* PSC 101 E. Gaine* Street Tallahsstee FL 32399-0850 DeFerrari, Dick Hgr-Rates/Reg Affrs Northwest Nat Gas 220 N.W 2nd Portland OR 97209 Dehart, Chuck Mgr, State Gov't Afr The William Cos. P.O. Box 2400 Tuls* OK 74101 Delkus, Kristine Attorney Morgan Lewis Bockius 1800 M Street, N.W. Washington DC 20036 DeMetro, Jane* VP, Energy Services Providence Gas Co 100 Weybosset Street Providence RI 02903 Pago: 06/23/93 NARUC-DOE National Conference on natural G*s Use New Orleans, Louisiana April 24-28, 1993

Principal Registrant Title Organization Address City State Zipcode

Devert, Thomas F. Senior Vice Preo. Coltzfcla Gas of Ohio 200 Civic Center Or. Colu&us OH 43216 DeUttt, D. OOUBUO Dir, Rate Research Baltimore Gel tElec Charles Center P.O. Box 1475 Baltimore 21203

Dingle, Steve Sr Lead ICP Analyst Entergy Services 225 Baronne 24th Floor Sew Orleans LA 70112 Dfxon, Stuart VP, Gov't Relations NC Natural Gas Corp P.O. Box 909 FsyetteviIle NC 28302 Doraan, T«» Vice Chairman Kentucky P5C 730 Schenkel lane P.O. Bex 615 Frenkfort ICY 40602 Ooud, W. Timothy Executive Director 10GCC P.O. Box 53127 Oklahoma City OK 73152 Dron, Rick Attorney lane t Mtttendorf 919 18th Street, H.W. suite ec-o Washington DC 20006

Dusfflan, 01 trine Asst. Consumer Advc Off of Consumer Advc 1425 Strawberry Square Harrftburg PA 17120 Dye, Richard Hgr, Fossil Engy Utt US DOE 1000 Independence Ave., SU FE-4 Washington 0C 205S5 Eason, Robert SW Marketing Manager Meridian Oil 2919 Allen Parkway Suite 1100 Houston IX 77019 Edelston, Bruce Dir, Bulk Pouer Pot Edison Electric Inst 701 Pennsylvania Avenue, KW Washington DC 20004-50DO Eelkema, Pete Research Economist Kansas CC 1500 S.W. Arrowhead Rood Topeka KS 66604

Ellis, Jeffrey Manager, DSH Bay State Gas Co 300 Friberg Parkway Uestboroujh HA 01581 Ellsworth, Bruce B. ConniisGionsr New Hampshire PUC 0 Old Suncook Rd. Concord NH 03301 » »"P« B^^^.w-BtaB _ f... Emerson, Geoffrey A. Dir, State Reg Affrs Panhandle Eastern 5400 Uestheimer Court Houston TX 77056 Empson, Jon SVP, Administration Peoples Natural G&s 1815 Capitol Avenue fccha HE 68102 Etkin, Honey US DDE 1000 Independence Avenue, S.W. KS CP-52 Washington DC 20585

Everett, Lee Dir, Reg Affairs Trans LA Gas Co P.O. Box 650205 Dallas TX 75265-0205 Fahey, Hi I Horn K. Attorney Foster Swift Collins 313 South Washington Square lapsing HI 48933 fanelly, Richard H. Commissioner Ohio PUC 180 East Broad St. Colurbus OH 43215 Farman, Dick CEO Southern Cat Gas 810 South Flower Street Los Angeles CA 50017 Fessett, Phil Mgr, Bus Analysis Warrick Operations P.O. Box 10 Newburgh IN 47630

Founce. Madonna Auditor Idaho PUC Statahouse Boise ID 83720 Fenlon, Mary K. Attorney Examiner Ohio PUC 180 E. Broad Street, 7th Floor Border, Slrig. Colurfeus OH 43215 Fernandez-WoUe, M. Attorney IV New Mexico PSC 224 East Palace Avenue Karien Ha!i Santa Fe 87501-2013 Fetter, Steve Chairman Michigan PSC P.O. Box 30221 Lsnsing m 48909 Fischer, Dave State Regulation Western Gas Hrktg 11 Greenway Plaza Suite 1129 Hosuton HI 77046 TX Fleming, Jr., Russell SVP, Gas Bus Unit NVSEG 4500 Vestal Parkway East Binghanton KY 13902 Flynt, Carey S>_pvr, Rates/Reg South Carolina EIG 6011 Shakespeare Road Columbia SC 29204 Foley, Michael Dir, Finan Analysis HARUC Post Office Box 684 Washington DC 20044 Fortmann, Rich Sr. Vice President Sierra Pacific Rescs P.O. Box 30150 Reno NV 89520-3150 Foster, Roy Director, Gas Supply Baltimore Gas t Elec P.O. Box 1475 Baltinore MD 21203

fmt, Michelle Michot Cntr for Pub Policy Univ of Houston 110 Heyne Building Houston TX 77042 Frantz, Bob Economist OT Dept of Nat Res 1520 E. 6th Avenue Helena HT 59620 Freitas, Christopher Natural Gas Analyst US DOE 1000 Independence Avenue, SV Washington SC 20585 Frick, Jaequelyn Principal Analyst New Orleans CCURO 1300 Perdido Street, City Hall Rooa 6E07 New Orleans LA 7C112 Frum, Richard D. Connissioner West Virginia PSC 201 Brooks St. P.O. Box S12 Charleston WV 25323

Frye, Mitt Project Leader Willlams Energy One William Center Tulsi OK 74172 Fryfog'.e, Jim Hgr-Doneatic Nat Gal Marathon Oil Conpany 5555 San Felipe Houston TK 77056 Furbacher, Str/e VP £ General Hsnager Chevron USA Prod Co 1301 HcKlmey Street Suite 247B Houston TX 77010 Gallaher, Frank SVP, Fossil Opera. Entergy Services 3838 Nortii Causeway Soulevard Metairic LA 70002 Garner, W. Lynn Reporter The Oil Daily 1401 New York Avenue, N.W. Suite 500 Washington DC 20005

Gartaan, John A. PSEIG 80 Park PUza T25 •rk NJ 07101 Page: 06/Z3/93 KARUC-DCE Nation*! eonferenca on Nictural Ca U*e New Orleans, Louliiana April 26-28, 1993 Principal Registrant Title Organization Address City State Zipcode Gass, C. Bernard Manager Arizona Pub Serv Co P.O. Box 53999 us eoso Phoenix AZ 85072-3999 Geehter, Jr., Richard Director, SE Hrktg KS Energy Marketing 125 St. Pauls Boulevard Suite 600 Norfolk VA 23510 Oeiss, Dick Executive Engineer Chrysler Corporation 14250 Plymouth Road Detroit M 43227-3086 Celder, Ralph H. Executive Director NECPUC 45 Memorial Circle Augusta K 04330 Glongrosso, Roy A. Dir, Coal Supply Entergy Strvices 3838 North Causeway Boulevard Metsirle U 70002 Gibbons, Mike Mgr, Customer Dvlmt ARKIA Gas Coupany Post Office Box 21734 Shreveport LA 71151 Ciesbrecht, Greg Mgr, Regulatory Afrs Pan-Alberta Gas 500, 707 - 8th Avenue, S.u. Calgary, Albt CAN T2P 3V3 Cflardi, John Correspondent Reuters News Agency 11 Greenwsy Plaza Suite 1200 Houston TX 77081 Gilbert, Bill it. Project Manager Duights Engy Resrch 1560 Broadway Suite 900 Oenver CO 80202 Gilbert, Don VP, Reg Affrs/Fin Vermont Cas System P.O. Box 467 Burlington VT 05402 01IIis, Matt VP, Marketing Northwest Pipeline 295 Chipeta Uay Salt Lake City OT 84158 Gilnore, Bill Analyst North Carolina UC P.O. Sox 29510 Raleigh NC 27612 Ginsberg, Susan U. Hgr, Regulatory Affr Coastal Gas Mrktg Co 2000 M Street, H.u. Suite 300 Washington DC 20036 Giordano, Sob President i CEO EnergyNorth Hat Gas 1260 Elm Street P.O. Box 329 Manchester NH 03105 Gipson, Dave Consul tent Pace Consultants P.O. Box 53473 Houston TX 77057 Glazer, Craig Chairmn Ohio PUC 180 East Broad Street Collates OH 43266-0573 (•lennon, Robert M. lawyer IN Util Cnsar Cnslr 501 N. Indiana Gov't Center Indianapolis IN 46204 Gonzalez, Jenet Energy Unit Manager Minnesota PUC 121 Seventh Place East Suita 350 St. Paul MM 55101-2147 Goodearle, J. Roy President Thunderbay Corp 7575 San Felipe Houston TX 77063 Goody, Alycit General Counsel Providence Gas Co 100 Weybosset Street Providence Rl 02903 Gordon, Kenneth Chairmn Massachusetts DPU 100 Csetoridg* Street Boston MA 02202 Grant, Gordon Special Counsel Aaerican Gas Assn 1515 Uilson Boulevard Roc* 1144 Arlington VA 22209 Grasso, James Mgr, Gov't Relations Algonquin Gas Trnsa 1284 Soldiers Meld Road Boston HA 02135 Gray, Alyse Executive Deputy Hew Tork PSC Three Eapire State Plaza Albany NT 12203 Gray, Bill Vice President Cogen Technologies 1600 Salth Street Suite 5000 Houston TX 77001 Greens, Andrew N. Attorney Shaw pfttnan Potts 2300 N Street, H.U. Washington DC 20037 Greene, Bill Dir, Gas Supply Cincinnati Gel t El* P.O. Box 960 Cincinnati OH 45201 Greer, Michael D. Vice President CHS Transmission 445 West Main St. Clarksburg uV 26301 Griffith, Julie Sr. Regulatory Anlst Panhandle Eastern 5400 Westhelaer Court Houston TX 77056 Grubb, Dan B. President Southwestern Energy 1083 Sain Street P.O. Box 1408 Ftyettevllle AR 72702 Grutur, Jay E. Palswr t Dodge 1 Beacon Street loston MA 02108 Crude, Wanda Policy Advisor Nevada PSC 4045 South Spencer street Suite A-tt Las Vegas NV 89117 Gulm, Chuck Deputy Comaissioner NY State Energy Off 2 Rockefeller Plaza Albany NT 12223 Guntharp, Shirley Dep Attorney General Arkansas Atty Gen 200 Tower Building 4th I Center little Rock AR 72202 Heeger, Kurt Hgr, Cas Sys Plmg Pub Serv Co of CO 122S 17th Street Suite 1100 Denver CO 80202 Hagan, Dave General Mgr., SPL Brooklyn Union Gas One MetroTech Center Brooklyn NT 11201-3850 Hall, John F. VP, Regulatory Mtrs Delta Natural Gas Co 3617 Lexington Road Winchester KY 40391 Hall, John 6. Vice President Aquila Energy Corp 2533 No. 117th Avenue Suite 200 NE 68164 Halt, Larry President and COO XN Energy P.O. Box 281304 Lcxewoed CO 80228-8304 Han, Jerry Oirector-NSC US DOE 900 Ccaaatrca Road E. New Orleans LA 71023 Hnil, Thomas I. Consultant Lev!tan t Associates 99 Suaser Street Suite 1720 Boston MA 02110 Hatmick, Patricia Vice President Natural Gas Supply 1129 20th Street, N.U. Suite 300 Washir«ton DC 20036 KMmond, Phillip R. Vice President Mlnnegasco 201 South 7th Street Minneapolis MN 55402 Hanaway, Paul O Commissioner Rhode Island PUC 100 Orang* Street Providence RI 02903 tw Page: 06122m HARUC-DOE Motional Conference on Natural Gas Use New Orleans, Louisiana April 26-28, 1993

Principal Registrant Title Orgariiation Address City State zipcode

Hanos, Gene Advisory Staff Alabama PSC P.O. Box 991 Montgomery AL 36104 Haney, Becky Senior Attorney Algonquin Gas Trrmsn 1284 Soldiers field 3oad 3oston HA 02135 Hanig, Jeff Manager, Energy Srvc HidCon Development 701 E. 22nd Street Lccbard IL 60148 Hanson, Darrell Manager Utah PSC 160 East 300 South P.O. Box 45B02 Salt Lake City UT 84145 Harden, Sick Wintnrop, Stimson One Battery Park P'oia Hew York 10004

Harper, Colin VP, Fuel Supply Cogen Technologies 1600 Smith Suite 5000 Houston TX 77002 Harris, Jeff Hgr, State Reg AffrB Panhandle Eastern 5400 Westheimer Court Houston TX 77056 Harris, Randy L. Accountant Mississippi PSC P.O. Box 1174 Jackson MS 39215-1174 Harrow, Donald F. VP, Gov't Relotions Piedmont Natural Gas P.O. Box 33G6S Charlotte IJL 28233 Hartley, Lynn Reporter Olatt's Oilgram News 3540 N. Arnoult Road Metairie LA 70002

Harvey, Steve Managing Consultant R.J. Rudden Assocs 611 Clermont Dallas TX 75223 Hastings, Bill Suvp, Consumer Mrktg Marathon Oil Company 5555 San Felipe Houston TX 77056 Hazeluood, Mark Sr. Vice President ARCO OiI & Gas Co P.O. Box 2819 Suite 41-127 Dallas TX 75221 Heath, Roger Assistant Director HH Office for Energy 57 Regional Drive Concord NH 03301 Heffernan, Barbara Partner Schiff Hardin Uaite 1101 Connecticut Avenue, H.W. Washington DC 20036

Heinkel, Joan Nat Gas Analysis US DOE 1000 Independence Avenue, S.W. El-400 Washington DC 20585 Heintz, Frank O. Chairman Maryland PSC 231 E. Baltimore St. African Bldg. Baltimore MO 21202 Heiser, Jr., Craig Hgr, Energy Practice Andersen Consulting 901 Main Street Pallas TX 75202 Hemingway, Lynn Hgr, Gov't Affairs Northwest Pipeline 295 Chipeta Way P.O. Box 58900 Salt Lake City UT 84158 Henderson, Kenny Staff Attorney Arkansas PSC 1000 Center Street P.O. Bex C-400 Little RocK AR 72209 Hewlett, Stephen C. Commissioner Utah PSC P.O. Box 45585 Salt Lake City UT 84145 Higgins, U.L. Executive VP HcDermott, inc. P.O. Box 60035 Mew Orleans LA 70160 Hill, A. Xaren Managing Counsel Niagara Mohawk Power 3000 K street, H.W. Suite 3C0 Washington DC 20007 Hill, William J. President Nat Fuel Gas Dist 10 Lafayette Square Buffalo NY 14203 Kite, George Powers Petro Cnstts 610 Highway 6 South Suite 110 Houston TX 77079

Hladick, Bob Rate Analyst Iroquois Gas Trnsmn One Corporate Drive Suite 606 Sheltjn CT 06484 Hoard, Jin Supervisor North Carotin* UC P.O. Box 29520 Raleigh NC 27626 Hochheiser, H. Willie Deputy Director US DOE 1000 Independence Avenue, S.U. Washington DC 20585 Hockadey, Donald Hall* lor Petroleun 1660 Lincoln Street Denver CO 80264 Hodges, Arden Dlr, State Gov't Afr Columbia Ges Trims P.O. Box 1273 Charleston uv 25325-1273 Hoehne, Hark E. AVP, Energy mgvieu Fibre Co P.O. Box 639 Longview HA 98632 Hoffman, Otto F. Deputy Exec Director Pennsylvania PUC P.O. Box 3265 Karrisburg PA 17105-3265 Kolbrook, S. Demfs Vice President National Fuel Gas 10 Lafayette Square Buffalo HI 14224 Hoilitter, Kenneth Vice President W.H. Reaves t Co 30 Montgomery Street Jersey City NJ 07302 Koines, Charles F. SVP-Gen Coun I Secy FH Properties, Inc. 1615 Poydras Street New Orleans LA 70112

Holt, Becky Hgr, Gas Operations South Carolina E I S 6011 Shakespeare Road Coliafaia SC 29204 Holtzlnger, Jack Partner Hewaan ( Holtzinger 1615 I Street, N.U. Suite 1000 Washington DC 20036 Hopkins, N&ry Ellen Dir, Washington Oper The Fleming Group 1700 Diagonal. Road Suite 720 Alexandria VA 22314 Hopper, John VP, Mktg I Reg Affrs Tejas Power Corp 200 Westlake Park Boulevard Suite 1000 Houston TX 77079 Hornby, Rick Assoc Dir, Nat Gas Tellus Institute 89 Broad Street Boston HA 02110

Hortng, Reed R. Hgr, Gas Acquisition Philadelphia Elec 300 Front Street W. Conshohocken PA 19428 Kotaan, Les H. Vice President The Berkshire Gas Co 115 Cheshire Road Pittsfield 01201 Houde, Tea O VP, Rates/Rsrce Pins Yankee Gas Services 599 Research Parkway Heriden CT 06450 P»9*: KMUC-OOE Kit too*I Conference on Natural Ss* UM warn New Orleana, Louisiana Aprii l 26-23Z68 , 199993

Principal Registrant Title Organization Address City State Ztpcode

Howard, Glen S. Counsel Process Gas Craars 1275 Pennsylvania Ave., KW Washington DC 20004 Howe, John B. Vice President J. Makowski Jutsocs One Bowdoin Square Boston NA 02114

Hughes, Patrick J. Program Manager Oak Ridge Nat Lab P.O. Box ZOOS, Bids- 31<>7 US-6070 Oak Ridge TN 37331-6070 Hughltt, Jerry President ( COO Washington Gos 1100 H Street, H.U. Washington DC 2ooao Huhmn, Steve Coord, Reg Affairs Conoco P.O. Box 2197 CH 1134 Houston TX Hut ton, Mary Ann Executive Director NH Indus Gas Users 9999 M.E. Worden Hill Road 0mfee OR 77077 Hydok, Joseph T. Executive VP Consolidated Edison 4 Irving Place Hew York KT 97115 10003 Itoh, Setsuo Researcher Osaka Gas Company 375 Park Avenue Suite 2SD5 Hew York NT 10152 Itteilag, Rich Director, Marketing Missouri Pub Serv Co 10/00 E. 350 Highway P.O. Box 11739 Kansas City HO 64138 Jackson, Allen General Manager Union Oil Conpany P.O. Box 4551 Houston TX 77210 Jackson, Bob Sr. Vice President Stone I Webster 250 W. 34th Street Hew York NT 10119 Jaffe, Ada* Professor Harvard university One Brattle Square MA 0213S

Jasso, At Oregon FUC 550 Capitol Street, H.E. Salen OR 97310 Jeffreys, Frank B. Dir. of Marketing Consolidated Mat Gas 625 Liberty Avenue CKG Tower Pittsburgh PA 15222-3199 Jennrich, John Edi tor Nature! Gas Week 1401 New York Avenue, H.U. Washington DC 20005 Johnson, Bill President ond CEO Gas Service 2460 Pershing Road Suite 2DD Kansas City MO 64108 Johnson, David vice President ARKLA P.O. Box 751 Little Rock AR 72203

Johnson, John Paul Hatural Gas Supply 1129 - 20th St. Suite 303 Washington DC 20036 Johnson, Soy E. President Tiberon Corp. P.O. Box 249U1 Hew Orleans LA 70184-4901 Johnston, J. Bennett U.5. Senator 136 Hart Building Washington DC 20510 Johnst";, Donald E. Principal Drazen-Brubaker P.O. Box 412000 St. Louis HO 63141-2000 Jones, Oavid R. President and CEO Atlanta Gas Coinpany 235 Peachtree Street, M.E. P.O. Box 4569 Atlanta GA 30302

Jones, Oick VP-Governraent Affrs Williams Net Gas P.O. Box 3288 Tulss OK 74101 Jones, Jerry Senior Rep Panhandle Eastern 5400 Westheimer Court Houston TX 77056 Jones, Ronald D. Chairman United Dist Cos. 125 W. 55th Street Mew York MY 10019 Jordan, Chuck Senior Consultant Cartridge Engy Resch 20 University Road Charles Square Cartridge HA 02138 Jordan, Matt Manager, LCP Entergy Services 2530 Chelsea Drive New Orleans LA 70131

Jordan, Vernon Senior Util Analyst Iowa Utilities Board Luces State Office Building Des Koines 1A 50319 Kachele, Andrew R. General Manager Uninin Corporation 258 Eln Street New Canaan CT 06S40 Karachiwala, Bud Manager of Marketing Midwest Gas 401 Douglas Street Sioux City IA 51102 Kearney, Julius D. Comissioner Arkansas PSC 1000 Center St. Little Rock AR 72201 Keegan, Robert Partner Keohane t Keegan 21 Custom House Street Boston MA 02202

Kelly, Ed Assistant Director Cambridge Energy 20 University Road Caofcridge HA 02138 Kelly, Jo Ann Cormissionor Nevada PSC 4045 South Spencer street Suite A-44 Las Vegas NV 89158 Kelly, Joe Dir, Reg/Gov't Affrs Columbia Gas of KY 70 Fountain Place Capital Plaza Frankfort ICY 40601 Kelly, Laurie Mgr, Economic Resrch Oklahoma CC 500 Ji» Thorpe Building Oklahoma City OK 73105 Kernnan, Bill G.F.I. Rep Stewart t Stevenson 5840 Dahlia Street Connerce City CO 80022

Kennedy, Thorns E. Dir, Gas Progran Illinois CC 527 East Capitol Ave. Springfield IL 62794 Kenney, Janes F. VP, Plng/Systen Oper Entergy Services 383S North Causeway Boulevard Metairie LA 70002 Keys, Jaaes R. Executive Director Temeco Inc. P.O. Box 2511 Houston TX 77252 Kiley, Ton President New England Gas Assn 75 Second Avenue Suite 510 Needhan HA 02194 Kinder, Richard President and COO Enron Corporation P.O. Box 1188 Houston TX 77251-1188

King, Carl Sr. Vice President Panhandle Eastern 5400 Westheimer Court Houston TX Page: 8 06/23/93 NARUC-DOE National Conference on Natural Gas Use Neu Orleans. Louisiana April 26-23, 1993

Principal Registrant Title Organization Address City State Zipcode

King, Jack L. President and COO Entergy Enterprises 900 S. Shackleford Rd, Ste 210 3 Finan Center Little Rock AR 72211 King, Justin R. Vice President Areo Oil I Gas Co 1601 Bryan 41-119 Dallas TX 75201 King, Richard Managing Attorney Hew Torn PSC Three Empire State Plaza Albany VI 12208 Kimeary, Bill General Kgr, Rates Brooklyn Union Gas One HetroTech Center Brooklyn NY 11201-3350

Kirk, Scott Henber/Comaissioner LA Nat Gas Mrkt Conn 909 Poydras Street Mew Orleans LA 70160 ICnopp, Allan Oirector, Res Affrs Conoco P.O. Box 2197 Houston TX 77252 Kosowski, Susan Research Anlys Spec Minnesota OPS 121 7th Place East Suite 200 St. Paul MH 55101-2145 Krebs, Hark Hgr, CctnVlndus Tech Southern Union Gas 400 W. 15th £*C0 Austin TX 78701 Kretschmer, Ruth K. ConmisS'ioner Illinois CC 100 West Randolph St. Suite 9-100 Chicago IL 60601

Kuhr, Shirley Consultant Amoco Production Co 18504 Osprey Circle Anchorage AK 99516 Kurtz, Bill L. VP, Go< Marketing Union Pacific Fuels Hai I Station 3201 P.O. 3ox 7 Fort Worth TX 76101-0007 Kwan, Billy Energy Analyst Colorado PUC 1580 Logan Street CL 2 Denver CO 80203 Kydes, Andy S. Sr. Tech Advisor US DOE 1000 Independence Avenue, S.U. El-80 Washington DC 20585 Lackey, Larry Financial Analyst Vermont DPS 120 State Street Kontpelier VT 05620

Ladd, Horibeth Hearing Officer Massachusetts DPU 100 Cartridge Street 12th Floor Boston MA 02202 Lagiovane, Peter Natural Gas Analyst US DOE 1000 Independence Aveneu, S.U. Washington DC 20585 Lamb, Bob Vice President Southwestern Energy 1083 Sain Street P.O. Box 1408 Fayetteville AR 72702 Lapp, Eli A. Vice President Lehanrt Brothers American Express Touer World Firsn ctr Net) York NY 10258-1000 Lorlcin, Jr., Hugh Lark in I Associates 15728 Feraington Road Livonia MI 48154

Lasher, Steven H. Attorney Foster Swift Collins 313 S. Washington Square Leasing MI 48933 Launer, Curt vice President Donaldson Lufkin 140 Broadway Hew York NY 10005 Lee, Jin Exec Vice President Colwfoia Gas Diet 200 Civic Center Drive Coluntxts OH 43215 Lemon, Rod Chrm, f'otit Econ Dpt Honmouth College Momouth IL 61462 Lerro, Paul U. President Transport Gas Co P.O. Box 110253 Pittsburgh PA 15232

Lesher, Oave Vice Chairman Arkansas Gas Cnsmrs 6603 West Broad Street Ridaond VA 23230 Leste, Christine Industi-y Specialist US DOE 1000 Independence Avenue, S.W. Washington DC 20585 Levin, John A. Assistunt Counsel Pennsylvania PUC P.O. Box 3265 Harrisburg PA 17105 Levine, Len Dir, UK Gov't Affrs TransCanada Pipeline 601 13th Street. Ml Suite 35C S. Washington DC 20005 Lique, Diane Dir, R«serve/Nat Gas US DOE 1000 Independence Avenue, S.W. El 44 Washington DC 20535

Little, John H. Partner Ernst * Young 1225 Connecticut Avenue, N.W. Washington DC 20036 Littlefeir, Andrew VP, Public Affairs HESA, Inc. 2600 Tranoell Crow Center 2001 Ross Ave. Dal Us TX 75201 Loftspring, Peter Attorney Seagull Energy Corp 1001 Fannin Suite 1700 Houston TX 77096 Lord, Thorns Morgan Stanley A Co 1251 Avenue of the Anericas New York NY 10020 Lou, Don Director of Uttls Kansas CC 1500 SW Arrowhead Road Topeka KS 56604-4027

Lowe, Oebra Principal Analyst Hew Orleans CCURO 1300 Perdido Street, City Halt Coot 6E07 New Orleans U 70112 Lucas, H.C. Manager Tenneco Gas P.O. Box 2511 Houston TX 77252-2511 Lucherfnl, Richard Asst til Comistioner Neu Jersey IRC Two Gateway Center Newark NJ 07104 Lund, Pettr G. Mgr, ml Business Ret Pacific Gas Trnsasn 1001 S.U. 5th Suite 1100 Portland OR 97204 Lykins, Carey B. VP, Cunt Svcs/Rates Citizens Gas fi Coke 2020 North Meridian ! Itreet Indianapolis IN 46202

Macey, Damy Editor Gas Daily 1616 N. Fort Myer Drive #1000 Arlingtoi VA 22209 Hacon, Karen M. VP, Hki:g t Reg Affra Mountaineer CM CO 414 Suaaer* Street Charleston WV 25301 Magruder, Kathleen Mgr, Hrktg/Gov't Afr ARCS Oil I faas Co P.O. Box 2819 Roca 38-052 Sal In TX 752Z1 Mahoney, Jia Dir of Fuel Supply Neu England Power 25 Research Drive Westborough HA 01582 Makowskf, Jacek Shafrann ( CEO J. Makowaki Astocs. 1 iowdofn Square •ocion MA 02114 Page: 06/23/93 NARliC-DOE National Conference on Natural Gas Use New Orleans, Louisiana April 26-28, ?9V3

Principal Registrant Title Organization Address City State Zipcode

Hatloy, Ken Off cf Oil/Nat Gas US DOE 1000 Independence Avenue, S.y. Washington DC 20585 Hanoi is, Brian Vice President Paribas Futures 787 Seventh Avenue New York NY 10019 Manshio, Calvin Attorney 4201 N. Sheridan Chicago il 60613 Martin, Hitch Staff Assistant Cincinnati Gos S Ele P.O. Box 960 Cincinnati OH 45201 Mattavous-Fryc, S. Assoc People's Coun Off of People's Coun 1133 15th Street, N.U. Suite 500 Washington DC 20005

Matthews, Craig CFO end Executive VP Brooklyn Union Gas 1 MetroTech Center Brooklyn NY 11201 Matthews, Oiedre Acting Ori, Gas Div Hasacfcusetts DPU 100 Cambridge Street Rooo 1207 Boston MA 02202 Haxheim, John H. President & CEO Piedmont Natural Gas P.O. Box 33068 Charlotte NC 28233 Hazanec, George President Texas Eastern Trnsmn 5400 Uestheimer Court Houston TX 77056-5310 McCartney, Mary Jens VP - Gas Supply ConEdi son 4 Irving Place New fork NY 10003 McCleery, R. Scott Regulatory Affairs Chevron U.S.A. P.O. Box 2100 Houston TX 77252 McCUskey, R.E. Sandy State Reg Afrs Coord Amoco Production 200 East Randolph Dr. (HC 4703) Chicago IL 60601 McClymond, Jim President Peoples Natural Gas 1815 Capital Avenue Cfcaha HE 63102 McCrea, Randy Mgr, Natural Gas Reg Shell Oil Company P.O. Box 576 Houston TX 77001-0576 McDonald, Polly Asst. Dir, Legal/Gas Texas Railroad Conm P.O. Box 12967 Austin TX 78711-2967

McDougatl, Gerry f. Vice President Washington Nat Gas 815 Mercer Street P.O. Box 1869 Seattle WA 98111 McGibbon, Tim Energy Support Sys IBM 2 Riverway Houston TX 77056 McGrath, Michaet P. Manager Intermountain Gas Co P.O. Box 7605 Boise ID 83707 HcGrcu, Christopher Asst Vice President Indus Bank of Japar 24""5 Par'--'•k Avenu ' e— New York NY 10167 McGuire, Hark J. Asst General Counsel Peoples Gas Light 12Z South Michigan Avenue Suite 320 Chicago II 60603 McKeage, Heather Analyst Enron Gas Services '400 Smith Houston TX 77251 HcKimey, J. Miles Hrktg Gov't Affairs ARCO OiI & Gas 1601 Bryan street R003 38-020 DAB Dalles TX 75201 HcKinney-James, Rose Comrnsr. ioner Nevada PSC 4045 South Spencer Street Suite A-44 Las Vegas NV 89138-3920 McHanus, H. Christie Oir, Hegulatory Rels Pacific Gas t Elec P.O. Box 770000 KC B10C San Francisco CA 94177 Mendoza, Mohn F. Chairman Nevada PSC 4045 South Spencer Street Suite A-44 Las Vegas NV 8915803920 Merrels, Andy Engy/i'urchases Cnslt Owens-Corning Fbgls Fiberglas Tower Toledo OH 43659 Meyers, Jeffrey Dir, Spec Res Projs Columbia Gas Dfst 200 Civic Center Drive Columbus OH 43215 Meyers, Kitty Market Researcher Georgia Power Co P.O. Box 4545 Atlanta GA 30302 Hickim, Luke A. Corporate Counsel Natural Gas Clmshse P.O. Box 4777 Houston TX 77040 Miller, Jennifer L. VP I General Counsel Boston Gas Conpsny One Beacon street Boston HA 02108

Miller, Kathleen Staff Louisiana PSC P.O. Sox 91154 Baton Rouge LA 70821 Moghadam, Brian Sr Rates Analyst Petro • Canada 150 - 6th Avenue, S.U. Calgary, Atbt CAN T2 Moore, Harry Manager Univ of Hissourl-KC 1011 E. 51st Street Kansas City MO 64110 Moore, Thomas E. President and CEO Natural Fuels Corp 5955 Stapleton Drive North Denver CO 80216 Moring, Frederick CrowelI I Horing 1001 Pennsylvania Avenue, N.U. Washington DC 20004-2595 Morris, Michael G. COO Consuners Power Co 212 V. Michigan Avenue Jackson Mi 49201 Morrow, Rick Mgr, Core Markets Southern Cal Gas 555 U. Fifth Street Los Angeles CA 90013 Morrow, Jr., Boyce Vice President Pub Serv Co of NC P.O. Box 1398 Gistonia NC 28053 Hosier, Pat B. Public Util Analyst Arkansas PSC 1000 Center Street Little Rock »S 72201 Mucci, Ron Vice President Uilliam Natural Gas P.O. Box 3288 Tulsa OX 74101 Muchow, David J. General Counsel American Gas Assn. 1515 Wilson Boulevard Arlington VA 22209 Mullen, Mary --> Enron Gas Services 1400 Smith Houston TX 77251 Muriceak, Cindi _^ Valuation Engineer Pennsylvania PUC P.O. Box 3265 Harrisburg PA 17105-3265 Page: 10 04/23/93 HAf!UC-DO£ National Conferen-e en Matures-. Gas Use Hew Orltins, Louisiona April 26-28, 1993

Principal Registrant Title Organization Address Citv State Zipcode

Hurphy, Terrence J. Vice President Columbia Gas of PA 212 Locust Street, «410 P.O. Box 905 H&Ti&burg PA 17108-OV06 Kurre'.i, Laura VP. Regulatory lemeco Gas Hrkting 950 Breckenridge Lane Louisville ICY 40207 Musssllan, Robert Chief Counse? Wisconsin PSC 4802 Sheboygen Avenue P.O. 8cx 7334 Hsdison WI 53707-7854 Kagcl, Dennis J. Chairperson Iowa Utilitiea Board luces State Office Bldg. Des Koines IA 50319 Neely, Pa« Reg Mgr, Gov't Affrs Northern Notural Gas 7055 Vista Drive W. Des Koines IA 50266-9311 Neff, Shirley Dir, Legislative Afr INGAA 555 13th Street, H.tf Suit* 320 yest Washington DC 20004 Noises, Kenneth J. VP, Fed Reg Affairs Laclede Gas Co 72G Olive Street 1512 St. Louis HO 63101 Heitzel, Scott Commissioner Wisconsin PSC 48C2 Sheboygon Avenue P.O. eox 7S54 Haidson WI 53707-7854 Nelson, Bud Consultunt Gas Research Inst 1331 Pennsylvania Avenue, K.W. Suite 730 Korth Washington DC 20004 Nelson, Ron Mgr, Mrkt/Sppt Servs Haxus Energy Corp 717 H. Haruood OallES TX 75201 Nelson, Sharon L. Chairman Washington UTC 1300 Evergreen Park Dr., SU Olyrpia WA 98504 Nemcrgut, Fred Vice President Reed Consulting 1050 Waltham Street Lexington MA 02173

Neustaedter, Robert Manager Temeco Gas 1010 Hilam Street P.O. Sex 2511 Houston TX 77252-2511 Nichols, Gerre President Nichols Oil Company 14232 E. Evaris Aurora CO 60014 Nichols, Marshall W. Executive Director National Petro Coun 1625 < Street, N.w. Washington DC 20006 Nichols, Nick vice President Hat Econ Resrch Assc One Main Street 5th Flocr Cacfcridge MA 02142 Hixon, Walty Dir, Reg Research Entergy Services P.O. Box 8082 TC3T-25 Little Rock AR 72202 Noel, Betty People's Counse' Off of People's Coun 1133 15th street, H.W. Suite 5CD Washington DC 20D05 Norling, Nancy M. Chairman Delaware PSC Post Office Box 457 Dover DE 19903 O'Brien, Terrrence G. Attorney Monroe 1 Leffiarm 201 St. Charles Avenue Suite 3302 Mew Orleans LA 70170-3300 O'Connor, Marge Senior Counsel Mobil Oil Corp 12450 Greenspoint Drive Houston TX 77060-1991 Odon, Charles Sunset-Houston 3531 Cypresswood Drive Spring TX 77388 Ono, Tomohiko Representative Chubu Electric Pwr 900 17th street, N.u. Suie 1220 Washington DC 20006 Owen, Rick Dir, Pwr Generation Mississippi Power Co P.O. Box 4079 Gulf port MS 39501 Pei, Lou VP-Risk Hgmt Servs ENRON P.O. Box 1188 Houston TX 77251-1188 Paladino, Robert C. Executive VP York Research Corp 280 Park Avenue Suite 2700W New York NY 10017 Palmer, Greg Director-Gas Supply Northern States Pur 825 Rice Street St. Paul MH 55117

Pardini, A. J. "Bud" Comissioner Washington UTC 1300 S. Evergreen Park Dr., SV Otynpia VA 98504 Parkinson, Gerry Coord, Util Srvt Kkt Westcoast Energy 1333 U. Georgia Street Vancouver, B.C. CAN V6E 3K9 Partridge, Jack Vice President Columbia Gas Dist 200 Civic Center Orive Columbus OH 43216 Fatrylo, Bob Sr. vice President Niagara Mohawk Power 507 Plum street Syracuse NY 13027 Pauling, Gene Petroleui Engineer US DOE 900 Commerce ftoxi E. New Orleans LA 70123

Pavte, Jin Dir, Hrkt Ptns/Resrc American Gas Assn 1515 Wilton Boulevard Arlington VA 22209 Payne, Leon K. Transcon Gas Pipelne 2800 Post Oak Bouetvard Houston TX 77056-6106 Perkins, Patricia D. Coaaicsioner Missouri PSC P.O. Box 360 Jefferson City HO 65102 Phares, Alan Executive Engineer R.W. 5«k and Assocs P.O. Box 68 Cotuitus NE 63602 Piaiza, Dolly Staff Louisiana PSC P.O. Box 91154 Baton gouge LA 70821

Pick, James "Randy* Manager, Gas Sales II I E 909 Poydras Street New Orleans LA 70140 Pierce, Joe Vice President AHKLA Gas Ccnpany Post Office Box 21734 Shreveport U 71151 Poitevent, Edward B. Phelps Dunbar 400 Poydras Street New Orleans LA 70130 Pope, Jack Exec Adain Assistant Tennessee PSC 460 Jenes Robertson Parkuay N«»hville TN 37243 Port, David Associate Editor Natural Gas Intlgn: P.O. Box 70527 Washington DC 20024 Porter, Erf r-.-j President Supply F-lrmg Assocs P.O. Box 678 Old Greenwich CT 06807 Page: II 06/23/93 NARUC-DOE National Conference on Natural Gts Use New Orleans, Louisiana April 26-28, 1993

Principal Registrant Title Organization Address City State Zipcode

powers, John Rate Analyst Niagara Mohawk Pur 507 Plin Street P.O. Bxo 5001 Syracuse NY 13250-5001 Premo, Paul H. Consultant - Nat GasResource Hgmt !nt'l 384 BelHarin Keys Boulevard Kovato CA 94949-5638 Prenda, Brian J. Senior Rep Algonquin Gas Trnsm 12B4 Soldiers Field Road Boston HA 02135 Prentice, Bill Assistant Counsel Northwest Nat Gas 220 NW Second Portlend Of! 97209 Prestemon, David L. Senior Counsel Hiagaro Mohawk Power 3000 < Street, H.W. Suite 303 Washington DC 20007 Prezorski, Paul Director, Gas Supply El izabethtown Gas Co One Elizabeth town Plaza Union NJ 07083 Prince, Dennis Hgr., US Natural Cos CAPP 2100, 350 - 7th Avenur, S.W. Calgary, Albt CAN T2P 3N9 Prioleau, Gwendolyn Ellis S Prioteau 1435 Fenwick Lane Silver Spring HO 20910 Purgason, Bob Dir, Info Services Williams Energy One Uillicms Center Tulsa OK 74172 ouiat, Allan Sr Staff Reg Rep Chevron U.S.A. 1301 McKinney Street Houston TX 77010 Robago, Karl Commissioner Texas PUT 7600 Shoal Creek Boulevard Austin TX 78757 Rana. Copal VP-Trunkline LNG Wet Panhandte Eastern 5400 Westhei.T£r Court Houston TX 77056 Randazzo, Eric G.F.I. Rep Stewart S Stevenson 1400 Destrehan Avenue Harvey IA 70058 Randazzo, Samuel Attorney Emens Kegler 8rown 65 East State Street Suite 1£B0 Coltrtus OH 43215 Rankin, Cliff Vtnson & Eikins 2500 first City Tower Houston TX 77002 Ranniger, Jim VP. Rotes & Regs Public Ser Co of CO P.O. Box 840 Denver CO 80201 Read, Michael CPA/Auditor Oklahoma CC Jim Thorpe Building Booa 5C0 Oklahoma City OK 73105 Reed, Robert E. Natural Gas Spvsr Alabama PSC P.O. Box 991 Montgomery AL 36101 Reeves, Hike Exec. Vice President Peoples. Gas tight 122 S. Michigan Avenue R^oo 227 Chicago IL 60603

Regan, C.~i Attorney Pillsbury Madison 1667 K Street, K.W. Suite 1100 Washington DC 20006 Reich, Steve Project Manager ICF Resources, Inc. 9300 tee Highway Fairfax VA 22031-1Z07 Reid, Gary Morketing/Gov't Afrs ARCO Oil & Gas Co 1601 Bryan St. Rocra 38-094 Dallas TX 75201 Reinbold, leo H. Cosmissioner Norti; Dakota PSC State Capitol •>2th Floor Bissarck KC 58505 Reynolds, Steve President and CEO Pacific Gas Trnsntsn 160 Spear Street San Francisco CA 94105

Richard, III, Rick Chairman and CEO New Jersey Resources P.O. Box 1463 Wall NJ 07719 Ridgley, Robert I. President & CEO Northwest Nat Gas 220 N.V. second Avenue Portland OR 97209 Rimington, Fred Dir, Public Affairs Northern Border Pipe P.O. Bn 3330 Omaha NE 68103-0330 Rismiller, Randy P. Dir, FERC Intrventn Illinois CC 527 E. Capitol Avenue P.O. sex 19250 Springfield IL 62794-9280 Roach, Mark Powers Petro Cnslts 810 Highway 6 South Suite 110 Houston TX 77079

Roberts, Hugh D. Sr Coord, Reg Affra Marathon OiI Co 5555 Son Felipe Houston TX 77056 Robertson, Jr., Roy Attorney Eichhom, Eiehhorn 8585 Broadway Suite 825 Merrill Wile IN Robinson, Scott S. President and CEO The Berkshire G03 Co 115 Cheshire Road Pitttfteld MA 01201 Rodgers, Paul General Counsel NARUC Post Office Box 684 Washington DC 20044 Rogers, Uarren K. Sr. Vice President Mississippi VIly Gar. 711 West Capitol Street Jackson MS 39211

Root, Colleen C. Attorney Houston Power * Lght 611 Walker Houston TX 77002 Rosenberg, Bill President E Cubed Ventures 555 13th Street, N.U. Washington 0C 20004 Rosenberg, Laurence Analyst Enron Gas Service* P.O. Box 1183 Houston TX 77251-1188 Rothfelder, Martin Hcrinr-.-ron t Scotland One Gateway Center Newark NJ 07102 Rothschild, Ed Dir, Press/Engy Pol Citizen Action 1120 19th Street, K.W. suite 630 DC 20036

Roybal, Gary G. Engineering Manager New riexics PSC 224 E. Palace Aver.ua Karfan Halt Santa fe 87501-2013 Ruback, Steven Dir, Gas Spply/Rates The Colunfcia Group 785 Uashtngton Street Canton MA 02021 Ryan, Dennis J. Hgr, Laws I Regs Phillips Petroleum P.O. Box 1967 Houston TX 77251-1967 Ryan, Michael R. Senior Coordinator Texaco, Inc. 1111 Bagby Suite 3515A Houston TX 77002 Samayoa, Judy Vice President UtiliCorp United 911 Main Street 30th Floor Kansas City HO 64106 Page: 12 06/23/93 NARUC-OOE National Conference on Natural Gas Use Hew Orleans, Louisiana April 26-20, 1993

Principal Registrant Title Organization Address City State Zfpcode

Sampson, Hark Purchasing Manager Guardian Industries State Hwy. #9 Richburg SC 29729 Samuels, Margaret Ann Federal Counsel OH 011 of Creanr Coun Coltrfeus OK Scharleu, Charles E. Chairman t CEO Southwestern Energy 1083 Sain Street P.O. Box 1^03 Fayetievilte AR 72702 Scheueraarvt, Karl L. Asst vice President IGS Interstate Gas 1233 Westtonk Expressway P.O. Box 433 Harvey LA 70059 Schiefer, Wars F. SVP, Hrktg/Gas Spply Piedmont Natural Gas P.O. Box 33063 Charlotte NC 28233

Schillo, Bruce Economist U.S. EPA 401 M Street, SU PH0221 Washington DC 20460 Scholten, Scott B. Senior Rate Analyst Colonial Cas Co 40 Market Street Bex 3064 Lowell MA 01853-3064 Schoppe, Steve Mitchell Energy Corp 150 Golden Shadow Woodlands TX 77331 Schroeder, Hark Akin, Gump, Strauss 1333 Neu Hampshire Avenue, KW Suite 400 Washington DC 20036 Schultz, Krfsten Analyst Oklahoma CC Jim Thorpe Building Boon 5(30 Oklahoma City OK 73105

Scotland, William A. VP, Government Rels TransCanada Pipeline 111 5th Avenue S.W. Calgary, Albt CAN T2P lit Scot in, Hark Vice President New York Mercantile 919 18th Street, N.U. Suite EDO Washington DC 20C06 Seifert, Mark VP, Regulatory Affrs Indepndt Petro Assn. 1101 16th Street, N.U. 2nd Floor Washington DC 20036 Serio, Joe Assoe. Cnsmr Counsel Off of Cnsmr Counsel 77 S. High Street 15th Floor Coiirfeus OH 43266-0550 Shane, William R. Natural Gas Supply 1129 20th Street, H.w. Suite 300 Washington DC 20036

Shannahan, Gary R. Manager of Rates Illinois Power Co 500 S. 27th Street Decatur IL 62525 Shapiro, Robert D. General Counsel Hassachusetts DPU 100 Cambridge Street 12th Floor Boston HA 02202 Sharkey, Donna Keohane and Keegan 21 Custom House Street Boston MA 02110 Shatkus, John A. Manager, Reg Affairs Pacific Interstate 633 U. Fifth Street Suite 5400 Los Anseles CA 90071 Shew, Rob Dir, Cormercial Hkts Atlanta Gas Light Co P.O. Box 4569 Loc. 1572 Atlanta GA 30302

Sherman, Steve Attorney Citizens Gas S Coke 2020 North Meridian Street Indianapolis IN 46202 Sherman, Thomas U Exec VP & CFO Bay State Gas Co 300 Friberg Parkway Uestborough HA 01581-5039 Shroyer, Russell Corp purchasing Hgr Kind I Knox Gelatin P.O. Box 927 Sioux City IA 51102 Silverman, Linda US DOE 1000 Independence Avenue, S.W. EP-S2 Washington DC 20585 Simpson, Carl D. Chairman Aft Elec Energy Cnsmr P.O. Box 927 Stuttgart AR 72160

Simpson, John F. Associate Editor Public Util Reports 2111 Wilson Boulevard Suite 200 Arlington VA 22201 Sistrunk, Karen Asst People's Coun Off of People's Coun 1133 15th Street, N.W. Suite 500 Washington DC 20005 Skaggs, Bob Exec vice President Columbia Gas Dist 200 Civic Center Drive CoLuitus OH 43215 Sloan, Michael Project Manager Engy/Envirn Analysis 1655 North Fort Hyer Drive Suite 600 Arlington VA 22209 Smart, David A. Attorney Vyott, Tarrant 250 West Main Street Lexington KY 40507

Smith, Douglas Powell Goldstein 1001 Pennsylvania Avenue, N.U. Sixth Floor Washington DC 20004 Smith, Harold Marketing Manager Petroleum Info Corp 5333 Uestheimer Houston TX 77056 Smith, Jed Dir, Hrkt Plng/Anlys Washington Gas 6801 Industrial Road Springfield VA 22151 Smith, Jim Chairman and CEO Orange and Rockland One Blue Hill Plsza Perat River KT 10965 Smith, Joan H. Commissioner Oregon PUC 550 Capitol Street NE Sales OR 97310-1380

Smith, Larry Vice President Shell Oil Company P.O. Box 2463 Houston TX 77001 Smith, Minturn Mgr, Energy Affair* Proctor t Garble P.O. Box 32 Hehoopany PA 18629 Smith, Patrick J. Energy Coodinator Big Bear Stores 770 Uest Goodale Boulevard Coluabus OH 43212 Smith, Veronica A. Deputy Chief Counsel Pennsylvania PUC P.O. Box 3265 Harrisburg PA 17105 Smoots, Carol A. Partner Metzger, HollU 1275 K Street, N.U. Suite 1000 Washington DC 20005

Smyth, Dick Commissioner Wyoming PSC 700 Uest 21st St. Cheyenne UY 82002 Sobelson, Nancy Manager, IRE Elizabethtotffi Gas Co !Vie Elizabethtown Plaza Union NJ 07083 Soon., Janet Staff Louisiana PSC P.1). Box 91154 Baton Rouge LA 70821 Page: 1! 06/23/93 4ARUC-D0E National Conference on Natural Gas Use New Orleans, Louisiana April 26-28, 1993

Principal Registrant Title Organization Address City State Zipcode Sonderman, Andrew Gen Counsel/Sectry Colwtoia Gas Dist 200 Civic Center Drive Colunbus OH 43215 Sonnier, Brent G. Advisor, Reg Affairs OXY USA, inc. P.O. Box 261C0 Gk 1 chora city OK 73126

Spanos, Evans Gen Mgr, Rates Gas Company of MM Alvarado Sqare KS-2616 Albuquerque NH 87158 Spencer, Barry A. Van Kompen Herritt 71 Broadway Ken York NY 10006-2601 Sprangers, John Senior Attorney Hirnega'sco 201 S. 7th Street Minneapolis HH 55402 Stobio, Victor President Hattador Petroleum 1660 Lincoln Street Suite 27C0 Oemrer CO 80264 Stagliara, Vito Acting Asst. Secrtry US DOE 1000 Independence Avenue, S.U. Washington DC 20585 Stalnaker, Jeff Auditor Arkansas PSC P.O. Box 400 little Rock AR 72203-0400 Standley, Jim Dir, Consulting Srvc Ouights Engy Resrch 1560 Broadway Suite 900 Denve CO 80202 Stapor, Mary Project Manager 1CF Resources, Inc. 9300 Lee Highway Fairfax VA 22031 Stefani, John F. VP, Gas Supply Washington Nat Gas 815 Mercer Street P.O. Box 1869 Seattle UA 98111 Stelz, Bill fuel Resources Anlys Orange end Rock I and One Blue Hill Plaza Pearl River NT 10965 Stenger, J.D. Director Uestpac utilities P.O. Box 10100 Reno NV 89520 Steuart, Allan H. Sr. Vice President Petroleum Indus Rsch 122 East 42nd Street Suite 516 New York NY 10168 Stitt, Jim Director Florida Power Corp P.O. Box 14042 St. Petersburg Fl 33733 Streeter, Ron Chief, Gas Rates Hew York DPS 3 Empire State Plaza IHth Floor Albany NY 12223 Strom, John A. Sr. Vice President Tejas Power Corp 200 Uestlake Park Boulevard 10th floor Houston TX 77079

Sundheifn, Frances I. Opty Public Advocate NJ Dept of Pub Advct 31 Clinton Street Newark HJ 07102 Sutherland, Ron Economist Argonne Nat'I Lab Washington DC Sutherland, Timothy President C.C. Pace Resources 4375 Fair Lakes Court Suite 2000 Fairfax VA 22033 Suaney, Tom President Harwood Capital 6161 Harwood Avenue Oakland CA 94618 Swanson, Gary Manager Univ of Missouri-KC 1011 E. 51st Kansas City HO 64110 Sweeney, Carolyn Rate Analyst Niagara Mohawk Pwr 507 Plim Street P.O. Box 5001 Syracuse NY 13250-5001 Take), Yutaka Mgr, Nat Gas/Fuel Dv Mitsubishi Im'l 520 Madison Avenue New York NY 10022 Tanaka, Toshiaki Mgr, Venezuela Proj Hitsubushi Corp 6-3, Marunouchi 2-Chroms CMyoda-ku Tokyo, Japan 100-86 Taniho, Akira Manager, Fuel Div Mitsubishi lnt'l 333 S. Hope Street Suite 2500 Los Angeles CA 90071 Tatsuteni, Mariko Resource Specialist Nat Resrcs Ofns Coun 1350 New York Avenue, N.w. Washington DC 20005 Tatum, Johnny President Willout Gas Company P.O. Box 1649 Hattiesburg MS 39403-1649 Taylor, Bob Mgr, Cost/Resrc Eval PSEtG 80 Park Plaza 11-B Newark NJ 07101 Taylor, Jack 0. GPH Gas Corporation 1300 Post Oak Boulevard Suite 600 Houston TX 77056-3011 Tennison, Steven Marketing MESA, Inc. 5205 N. O'Connor Irving TX 75109 Terrazas, Richard Dir, Mktg/Operatlons 6P Gas, Inc. 200 Uestlake Park Boulevard Houston TX 77079 Terzic, Branko Commissioner FERC 825 North Capitol Street, N.E. Washington DC 20426 Thibdaue, Lisa J. Dir, Regulatory Affr Consumers Power Co 2000 Michigan National Tower Lansing HI 48933 Thomas, Kathryn Lead Analyst - Gas Washington UTC 1300 So. Evergreen Park Or, SW us nr-11 olynpia WA 98504 Thomas, Tina Assoc Dir, Reg Affrs Gas Research Inst 1331 Pennsylvania Avenue, H.U. Suite 730 North Washington DC 20004 Thompson, Ann Policy Analyst NARUC P.O. Box 684 Washington DC 20044 Thompson, Chuck Mgr, Fuel Regulation Southern Cat Edison 1190 Durfee Avenue South El Monte CA 91733 Thompson, Kevin Project Aduin. El Paso Natural Gas P.O. Box 1492 El Paso TX 79978 Tibbetts, Tyler Partner Ernst I Young 1225 Connecticut Avenue, N.W. Washington DC 20036 Tifft, Michael W. Director Heic Orleans CCURO 1300 Perdido Street, City Hall Rocs 6E07 New Orleans LA 70112 Tipton, Dan 0. Dir, Fuel Procuremnt US Generating Co 7475 Wisconsin Avenue Belh-sda HD Z0S14

Tomer, Brad General Engineer US DOE 3610 Collins Ferry Road P.O. Box 880 Morgantown 26507-0880 Page: 14 06/23/93 NARUC-DOE national Conference on Natural Gss Use Hew Orleans, Louisiana April 26-28, 1993

Principal Registrant Title Organization Address City State Zipcode

Trabandt, Charles 3667 K. Harrison Street Arlington VA 22207 Trent, Anthony T. Director, Purchasing Vista Chemical Co 90D Threadneedle Houston TX 77079-2990 TunnelI, Daniel R. President Pennsylvania Gas P.O. Box 605 Harri&burg PA 171 OS Tuohy, Dennis Auditor Wisconsin PSC 4802 Sheboygan Avenue P.O. Box 7B54 Kadison UI 53707-785* Turner, Gerald Vice Pres-Rates Alabama Gas Corp. 2101 Sixth Ave. North Birmingham AL 35203 Turner, Joseph President I CEO Environ Fuels Techs 10877 E. 11th Street Tulss OK 74133 Turner, Tim State Leg/Reg Affrs Phillips Petroleum P.O. Box 1967 Houston TX 77Z51 Tussing, Arlon President ARTA, Inc. 1001 fourth Avenue Suite 4730 Seattle IM 98154 Tvrdik, Penny SVP, Gas Wrktg/Spply Peoples Natural Gas 1815 Capitol Avenue Ccaha NE 68102 Ulrey, Jerry VP, Regulatory Affrs Indiana Gas Company 1630 N. Meridian Street Indianapolis IN 46220-1496 Vanderfcerg, Nancy Dlr, Stote Reg Affrs Transwestern Pipeln 101 California Street Suite 3170 San Francisco CA 94111 Vanderpool, Jonet Hgr, Hrkt Develprnt AHR Pipeline Company 500 Renaissance Center Detroit MI 48243 Voszily, Joseph A. Manager Brooklyn Union Gas One MetroTech Center 3rooklyn NY 11201 Verdun, Dan Adm, Fed Gas Reg Htr NYSEG 4500 Vestal Parkway East P.O. Box 3607 Binshsnton NY 13902-3607

Vessels, Tom President Vessels Oil t, Gas 1050 17th Street Suite 2003 Denver CO 80265 Voorhees, Steve Sr. Vice President Scnat Energy Servs P.O. Box 2563 Birainshan) AL 35202-2563 Vuchetich, Kathy VP ( General Manager West Ohio Gas Co 319 West Market Street Lira OH 45801 Unas, Gene Hgr, OSH Programs Peoples Gas Light 122 S. Michigan Boon 915 Chicago IL 60603 Uaddick, Chris Hgr, Reg Plng/Acctg Centra Gas Ontario 200 Yorklend Boulevard North York, Ont CAM H2J SC6 Wagner, Chad Energy Development Kosston LA 71043 Waisley, Sandra Actg Dir, Oil/Gas US DOE 1S00 independence Avenue, S.W. Washington DC 20585 Walent, Ken: Senior Analyst Wisconsin PSC 4802 Sheboygan Avenue P.O. Box 7854 Madison Wl 53707-7854 Walker, Brian Manager Andersen Consulting 901 Main Street Suite 5400 Dallas TX 75202 Walker, Mary Ann Shaw Pittmsn Potts 2300 N Street, N.W. Washington DC 20037

Wai rod, Janet President Resource Ping Group 171 Weatherbee Drive Westwood KA 02090 Wattman, John I. 01 rector-Fossil Fuel UI Pub! ic Serv Corp 600 N. Adams P.O. Sox 19002 Green Bay WI 54307-9002 Wardelt, Bob Mgr, Rates/Reg Affrs West Ohio Gas Co 319 West Market Street lima OH 45801 Wass, Leonard Vice President Towers Peer in 500 Boylston Street Boston «A 02116 Watson, Harry E. Valero Gas Hrktg 1350 I Street, N.W. Suite 1240 Washington DC 20005 Watson, J. Tin Consultant Watson Consulting 16376 S.E. Van Zyt Road Clackaou OR 97015 Weaver, David C. Legislative Counsel Sonar, Inc. P.O. Box 2563 Birmingham AL 35202 Webb, David 0. SVP, Pot I Reg Affrs Gas Research I rat. 1331 Pennsylvania Ave., HV Suite 730K Washington DC 20004 Webster, Rob Dir, Gas Plng/Procur PacifiCorp 201 South Main Street Suite 2100 Salt Lake City UT 84140-0021 Wernet, Debbie Vice President Enron Finance Corp 1400 Smith Street Houston TX 77002 West, Bill Mgr, Energy Planning International Paper 6400 Poplar Avenue Heaphis TN 38197 White, David Manager, Marketing Northwest Pipeline 16000 Christensen Road Suite 302 Seattle WA 98188 Whiteaker, Kathleen Regulatory Cons It ARCS OiI and Gas 1601 Bryan Street Km 38-044 DAB Dallas TX 75201 Whitcltt, Bill Vice President Oryx Energy Carpeny P.O. Box 2880 Dallas TX 75221-2880 Wickstrom. Charles Executive Director Hid-States NGV Coal 2820 Mid-Continent Totier TuUl OK 74103

Ulelgus, Paul Dir, Regulatory Afr* Enron Gas Services P.O. Box 1188 Houston TX 772S1-1188 Wike, Antoinette Chief Counsel North Carolina IX P.O. Box 29520 Raleigh NC 27626-0520 Wilkerson, Walter J. Special Counsel Wilkerson, Henry 650 Poydras Street Suite 1913 New Orteens LA 70130 Willett, Bob Associate Publisher Natural Gcs Magazine 4200 Uesthetmr Suite 114 Houston TX 77027 WilllaM, Arlty O Economic Analyst NM Dept of Fince/Ada Bataan Menorial tuildino, Rooa 180 Santa F» MM 87503 '3 Page: 15 06/23/93 NARUC-OOE National Conference en Natural Gas Use New Orleans, Louisiana April 26-23, 1993

Principal Registrant Title Organization Address City State Zipcode

Williams, Burch Mgr, Project Devlrat Millions Energy One Wi I liens Center Tutsa 74172 Wit t idns, Greg Attorney Horlcy Caskin 1225 Eye Street, H.U. Suite 402 Washington DC 2C305 Williams, Joe Utils Rate Analyst Kansas CC 1S0D SW Arrowhead Road Tcpeko KS 66604-4027 uilmarth, Fiona Rate Case Rev Spec Pennsylvania PUC 110 North Office Building P.O. Ecx 3265 Harrisburg PA 17105-3265 Wilson, Peggy Councilman City of New Orleans 1300 Pcrdido Street Kew Orleans LA 70112

Wilson, Jr., Kenneth Director, Cas Supply Entergy Services 3836 North Causeway Boulevard Kstairie LA 70002 Winger, Lee Mgr, Rev Reu A"lys Arizona CC 1200 U. Washington Phoenix AZ G5007 Winikou, Linda VP, Corp Policy Orange t Rockland One Blue Hill Plaza Pearl River NY 10965 Winters, Tobey Mgr, Market Analysis ABB Power Plant Sys 1000 Prospect Hill Road Windsor CT 06095 Wise, Eic Counsel American Gas Assn. 1515 Wilson Blvd. Arlington VA 2220? Wise, Jim P. Chairman t, CEO NeaStar Group, Inc. 3414 Oanbury Place Houston Wise, Richard W. VP & General Counsel Mississippi VIly Gas P.O. Box 3348 Jackson 39207 Wisner, Jio Regulatory Affairs Chevron U.S.A. 1301 HclCinney Hcuston TX 77010 Witkoski, Eric Asst General Counsel Kansas CC 15U0 S.W. Arrowhead Road Tcpska KS 66604 Wood, R.L. Secretory/Treasurer Justiss Oil Conpeny P.O. Box 1385 Jena LA 71342 Worthon, R.L. (Skip) Vice President Intermountain Gas Co P.O. Box 7608 ID 33707 Uortley, t*j. J. SVP, Public Affairs Washington Nat Cos P.O. Box 1869 Seattle WA 93111 Wright, Bob Director, Marketing HG Refining/Mrkting 19 Newport Drive forest Hill HO 21050 Wright, Hary Staff Attorney Hintana Cnsmr Coun 34 U. 6th Avenue Helena MI 5V620 Wyner, Husha Dir, Gas Division Hcu Jersey BRC Two Gateway Center Heuark HJ 07104

Yasuda, Kenneth E. Utility Analyst New Hampshire PUC 8 Old Suncook Road Concord HH 03301 Yoho, Frank VP, Corp Dev/Gas Sup Public Serv Co of NC P.O. Box 1393 Gastonia NC 28053-1398 Yokoyaraa, Tokash Venezuela Proj Teats Mitsubishi Corp 6-3, Marunouchi 2-Chrcre Chiyoda-ko Tckyo, Japan 100-86 York, Michael T. US DOG 1000 Independence Avenue. S.W. EP-52 Washington DC 20585 York, Teddy Production Sprtndt DSM Chenicals, NA P.O. Box 2451 Augusta GA 30903

Yount, Jay E. Regulatory Spec Chevron 1301 McKimey Houston TX 77253 Yurek, Stephen A. Dahlen Berg ( Co. 2150 Cain Bosmrth Plaza 60 S. 6th St. Minneapolis KH 55402 Yurkonin, John Vice President BP Gas, Inc. 200 WEstlake Perk Boulevard Houston TX 77079 Zeiszler, Don Williston Basin Ppln 200 K. 4th Street Bismarck ND 58501 Zckoll. Jack Director, Gas Unit New York DPS Three Empire Stats Plaza Albany NY 12223 Zelewski, A.V. Lloyd Regulatory Const t 1331 lamer Suite 145° Houston TX 77010 Zielinski, Paul air, Plrmg/iieg Polcy Rocheste^ Telephone 180 South Clinton Ave. Rochester NY 14646 Zimmermen, Dale R. Marketing Manager Plains Petroleum 12596 West Sayaud Suite 403 lakeuood CO 30228 Zinkham, Jeff Environmental Affrs Amoco Production Co P.O. 8ox 3092 Houston TX 77253 Zuraski, Richard J. Senior Economist Illinois CC 527 E. Capitol Avenue P.O. Bex 192S0 Springfield 62794-9280 JUN-B3-19SG 12=54 FRO1 NH PUBLIC UTIL COW TO 91202B982213 P.B2

outline of Comants Bruce 8. Ellsworth Coamisoloner Nsw Hampshire Public utilities Comnission NASUC-DOK conference on Natural Gas Uoo April 26-28, 1983

Recognize Ken Malloy and DOE Staff R«cogniE« MiXo Foloy and NARUC Staff Aoknovlcdgo 600+ attandanc*

N«v England parapectiv*

NARUC communications opportunities A» in industry, regulators m»y «groo or disagr*«, but th*r« ia valun in communications

Bach servic* ar«a 1B uniqu* Weather Supply availability LDC capability

Industry status Favorable public image Favorable safety record Low cost supply Adequate reserve* Governmental support at all levels Clean air Act Energy Strategy

R-95K 06-03-93 12r53PK P002 U10 JU+-03-19SG 12=54 FROM MH FUBLIC UTIL 00*1 TO 912023982213 P.03

Market opportunities G&B Cooling Electric Generation Natural Gas Vehicle* Industry is not adequately reacting to positive environment

Expand franchises

Rationale for accepting FERC Order 636 ?e

Coordinate snail coapany purchacin^ practices "Mansfield Coneortiua" •xaaiplo

G&B Research Gas Research Institute Xncreased DOB ceawiitnont

Regulator^' focus More, rather than less, regulation Focus on marginal costs - coat of service studies integrated Resource Flans Frud«vt us* of ?*&Jc Shaving M&xinize eoapetitiva purchKoing Pipeline, producer testimony before state regulators

06-03-93 12:53PU P003 t»10 JUN-03-19S3 12S55 FRO1 hH FUBLIC UTIL. COH TO 912B299H2213 P.04

Pipeline aafaty unaccountad fore Cast Iron replacement program Sxcess flow valves Industry aust instill confidence that they're working together Assure regulators: industry is aware that options exist Evaluated all options Inauntry «ust parsuada ragulatoxs that they know what thay'r* doing, in ordar to Bininica regulatory intrusion Producers, pipedinaa affactad by otata regulatory actions Transportation ratas Purchasing options

Communications LDCs must coxaunicat* with e&ob other IiDCs oust oomiuniottt with stata ragulators Find a friendly staff contact

In final analysis, industry will rise or fall together Ho opportunity for ona segnent of industry to avoid responsibility of system failure Don't be so infatuated by low spot pipeline prices that reliability io ceutpraml«et3

Industry cane to this torus to bear regulators' reactions to issues ULnit apeecb tinea to allow all presentations Allow adequate tiso for audieno* gusctions

Profound respect for industry

00-03-93 )2:53PM P004 «10 JUNrfl3-1393 12155 FROM m PUBLIC UTIL COW TO 91202B982213 P.05

Ab«olut» confid«io« Ui lndu»tory ability to nock tog«th«r to ••rv« eustoMrm

K-93X 06-03-93TTf:5?pffC P005 #10 Acting Assistant Secretary For Policy

Department of Energy

Before

The DOE/NARUC Conference on Natural Gas

New Orleans

April 26,1993

i t Good Morning, Ladies and Gentlemen. I am delighted to share the privilege of welcoming you to this important conference.

I bring the regrets of Secretary O'Leary who could not be here today because of a scheduling conflict, and hopes for your understanding.

I want to, first of all, thank the people who, for nearly a year have labored to organize this conference. Especially, the

National Association of Regulatory Utility Commissioners- key officers: Mr. Dennis Nagel, Mr. Bruce Ellsworth and Mr.

Frank Heintz; and on the NARUC staff, Paul Rogers, Mike

Foley and Anne Thompson.

(V>8 On my staff, the burden and challenge of assisting with this

conference fell first of all to Ken Malloy, and to Mike York

and Linda Silverman. And I want to thank them publicly for

their efforts.

We are here, in the magnificant city of New Orleans, for what

I call Natural Gas Week. During the next five day we will explore a wide variety of issues related to the regulation of natural gas and its future role as one of the critical fuels that powers the economy of the United States.

We will focus mainly on problems, obstacles, barriers, and the incredibly complex system we have created to bring a fuel from wellhead to burner tip. 3

But before we start on the problems, I want to start the morning by celebrating real achievement.

I have been at the Department of Energy for nearly 14 years.

In that time, perceptions and reality in the natural gas market have dramatically changed.

We believed in the 1970s that natural gas was a precious commodity to be used sparingly. And we believed that governments, rather than markets, should ration this fuel and protect the interests of consumers.

Every government in the world viewed the natural gas market in similar terms. In Europe, dependence on natural gas from the Former Soviet Union, was considered a national security issue.

0 0 4

Those of you who have shaped the natural gas industry know better than I how difficult it has been to change both perception and reality.

But you have.

And we are here today, among other reasons, to celebrate the triumph of logic over the inertia of public policy. We are celebrating, three months late, the landnmark legislation which set the course for decontrol of the natural gas market: the

Natural Gas WellHead Decontrol Act of 1989. (1/1/93 completion)

The Natural Gas industry is still over-regulated. Yet the benefits of de-regulation are nearly self evident.

031 Since open access transportation began in 1985, gas prices

have declined for all classes of customers.

Residential and commercial customers have greatly benefited from deregulation.

The only people who havent benefitted have been producers.

But their day will come.

The natural gas market has no natural limits, really.

We, and the rest of the world have abundant resources. The only limit is our willingness to use them. 6 We can put natural gas to work in virtually every end use

sector, and in every form, gaseous or liquid or compressed.

Remaining technology problems - such as they are - are being

addressed and represent no insurmountable hurdle.

The only limit lies in our imagination, and in our ability to

continue to reshape the scope and structure of regulation until

common sense finally prevails.

To reach this fmal stage of common sense, there is plenty of

work to be done by a great many people. Let me mention a

few of the issues that need our collective attention:

Public Utility Commissions, electricity generators, and natural gas transporters need, in my view, to intensify their contacts and dialogue. From a technology efficiency point of view, from an environmental point of view, and from an economic point of view, natural gas should be the fuel to beat for new power generation capacity increments in the 300 to 500 megawatts range. Will it be? and if not, why not?

We havent seen the end of FERC Order 636. There remain a great many nervous players in the game. Consumers are worried about costs shifts inherent in fixed/variable rate designs; liberal recovery of transition costs; potential for loss of capacity. Many members of Congress are also concerned about effects on consumers. If we're not careful, the debate on Order 636 will follow the 'lassical split of producers versus consumers. The same split that divided Congress on pro-rationing. Will State and Federal regulators find common ground; avoid 50 distinct State responses to 636; be wise enough to satisfy both national and local objectives? We have embarked upon a major shift in fuels and technology

for the transportation sector. The shift began with passage of

the clean air act amendments of 1990, and was secured by the

Energy Policy Act of 1992. What we see is a dramatic

increase in the use of oxygenates in gasoline. The key

competitors will be mcthanol, MTBE, ethanol and ETBE.

Methanol-based oxygenates, produced from natural gas

feedstocks, are likely to maintain their competitive edge. We project that under full opt-in conditions, oxygenates will replace one of every three gallons of oil for gasoline after

2000. Couple this with the strong alternative fuels provisions of the Energy Policy Act, and I think you will reach the conclusion that a brand new, very significant market, for natural gas - as a feed stock and as a fuel - is emerging in the transportation sector. Will State and Federal laws facilitate or hamper this shift? 9

Clearly, natural gas is at the top of the energy policy agenda

of the Clinton Administration. Two important iniatives have

already been taken. The first was to substantially increase the

DOE research and development budget for natural gas, from

about $110 in fiscal '93 to $200 million in fiscal 94. The

second, which is imminent, is the issuance of an Executive

Order with very aggressive goals for Federal purchase of

alternative fuel vehicles. The Administration will be watching,

I think, for opportunities to further enhance natural gas use.

And the President's commitments on global climate change are likely to present immediate opportunities for the natural gas industry. Industry can, and should, continue to hold the

Department of Energy's feet to the fire, to assure that National policy enhances the options.

OoS 10

National policy is ultimately a high wire act. The diversity of interests that comprise our common goals is not easily reconciled. We are a great energy producing country and a great energy consuming country. And we are unique in the world in being so. But I happen to believe that we do a pretty good job on the energy front. We are world leaders in energy regulatory reform. And, notwistanding the media, we are also world leaders on the environmental front.

Ladies and gentlemen, you have made us so. I wish you a splendid conference and thank you for your kind attention.

Q--7 o i E3 VENTURES, INC.

CLEAN AIR:

LEVEL THE NOX PLAYINO FIELD FOR ALL FUELS

BY WILLIAM G. ROSENBERG PRESIDENT, E-3 VENTURES. INC.

AT THE DOE/NARUC NATIONAL CONFERENCE ON NATURAL GAS USE NEW ORLEANS, LOUISIANA

APRIL 26. 1993

Soturums/or Environmental and Energy Choflntges u O O

535 TMRMnth StrMI. N.W. Washington. O.C ZQOOO Tal: 202/637-BC50 Fax: 202/837-8910 1139 KilOalra Farm Road. Suit* 33B-4 Cary. N.C. 27511 Tal: 810/469-3737 Fax: 913/46»-MS6 Over the past 4 years. ENORMOUS PROGRESS has been made so clean America's air:

• President Bush proposed the comprehensive Clean Air Act Amendments in May, 1989, just 5 months after taking office;

• Congress passed the CAAA of 1990 on November 15,1990 (401-25 in the House; 89-11 in the Senate.) These numbers represent on overwhelming mandate from the American public, and they establish a clear national agenda for ongoing work in the 1990s;

« EPA promulgated or proposed 80 foundation rules by January 20,1993 (the last ones were signed by Bill Reilly at 11:15 on Inauguration Day).

What was specifically accomplished?

The Clean Air initiatives will reduce pollution by 48 billion pounds per year, or 224 pounds lot each man, woman and child, at a cost of only .25 per person, per day.

• ACID RAIN will be reduced by 10 MM tons of SO2 and 2 MM tons of NOx.

• This will be accomplished under an innovative MARKET BASED ALLOWANCE TRADING SYSTEM. The first auction was successfully held by the Chicago Board of Trade in April. What could be more enterprising, more market-based, than the trading of emissions futures right along-side soybeans and pork bel'ies?!

• CARS ARE GETTING CLEANER: 50% cleaner. Next fall, new cars will emit 50% less VOCs and 60% less NOx than cars sold today in the showrooms.

• CLEANER GAS STATIONS: By 1994, all gas station pumps in non attainment areas will cut exposure to toxic gasoline vapors and save fuel that evaporates into the atmosphere.

• BETTER MAINTAINED CARS: EPA's high-tech auto inspection and maintenance program will do more to reduce air pollution than any other single measure. Improved auto testing in most polluted areas will assure that cars are properly tuned, than hoses don't leak, and that the catalyst is not touched.

• CLEANER BUSES: Administrator Browner has finalized urban bus standards that cut the black diesel cloud 90%. Cleaner diesel fuel is being reformulated to contain less sulfur.

• CLEAN CAR FLEETS: A substantial fraction of new vehicles purchased by centrally fueled fleets in serious and severe non attainment areas, shall be required to be clean alternatively fueled vehicles stamng in 1998. In addition, earlier introduction of cleaner fleets can generate pollution credits under a mobile stationary source trading program.

• AIR PERMITS: The effectiveness of state and federal rules will improve with accountable and flexible air permits.

• THE AIR IS GETTING SAFER TO BREATHE: CFCs will be phased out of production in the US by 1995. This year freon recycling began. Some auto companies (Nissan, Ford, Volvo) have already started producing air conditioners using CFC substitutes.

03!) GREENER LIGHTS AND COMPUTERS: 700 companies - many represented in this room - pledged to retrofit 2.67 billion square feet to energy efficient lighting. That's the equivalent of all the office space in New York, LA, Chicago, Dallas and Washington combined. And computer manufacturers beginning this summer will produce computers that power down when not in use, saving the equivalent of a 1 SO watt bulb that burns full time. By the end of the decade, in the aggregate, that will reduce the need for the equivalent of 5 power plants, thereby eliminating that much pollution.

HOW WAS THIS ALL ACCOMPLISHED?

The greatest progress came through NEGOTIATED RULE MAKINGS, where all the parlies sat down together - industry, environmentalists, state regulators and EPA, - and agreed to proposals that led to more environmental protection, at lower costs, through market-based incentives.

The NA VAJO POWER PLANT, at the rim of the Grand Canyon, is installing SO2 scrubbers under an agreement between the utility owners, EDF, the Grand Canyon TnU, the State of Arizona and EPA. 90% of the emissions that impair visibility at this national treasure will be cut at a savings of 25% from traditional EPA approaches.

COKE OVEN toxic fumts will be much lower. Instead of the grand jury investigations of the 1970s, USX, Bethlehem Steel, United Steel Workers, NRDC. Sierra Club, numerous states and EPA all worked out cm agreement to overhaul this most toxic point source at 10% of the cost estimated by the steel Industry during the Clean Air Act debates,

The ACID RAIN rules were negotiated u".der the auspices of the Acid Rain Advisory Committee; 44 members from the electric utilities, natural gas anti coal industries, state cir regulatory agencies, PUCs, environmental community and EPA.

But the GRAND DADDY of all negotiated rule makings was the Reformulated Gasoline Rules which will achieve 15% less VOCs by 1995. and 25-35% less by the end of the decade.

OP March 26, the USA Today headline read: "New Fuel Slashes Smog". The story began, "a new wintertime clean fuel program has dramatically improved urban air quality ...with wintertime air quality tests in. the Environmental Protection Agency couldn't be more happy: 38 urban areas using oxygenated gasoline recorded two days of unhealthy carbon monoxide levels. This number is down from 45 days a year ago, and down from 113 days in 1990." The lesson: CLEANER FUELS REALLY DO WORK, and in my opinion, NGV vehicles driving on clean natural gas will work even better!

THERE WAS A FAIRLY CLEAR road map to follow over the past few years, although I must admit to falling into a number of potholes -- some say, head first! However, the future course is much more confusing .

What's AHEAD is not only EPA implementation of remaining Congressional statutory mandates, but also development of State Implementation Plans in each state which will be designed around local air quality needs.

I'd like to talk about the enormous potential that exists for natural gas within these state ozone strategies.

As states, businesses and environmentalists survey what's ahead, two principles that should be guiding lights: BOTH

1. Least cost community attainment strategies; AND

2. Least cost business compliance strategies.

010 The key word is BOTH. To effectively participate in the SIP process, parties must emphasize BOTH meeting ambient air quality standards fo; public health, AND managing compliance cost and promoting innovition. It will require:

GOOD SCIENCE, GOOD ECONOMICS, GOOD REGULATIONS, and GOOD WILL - most importantly, CONTINUED GOOD WILL.

As states make their choices in developing the State Implementation Plans, especially in the most serious concentrated non attainment areas like the Northeast, a dominant issue is likely to be NOx polution. That's where the biggest issue is shaping up, because that's where the greatest new efforts will be required to clean up the air, and where gas will play a very large and important role as a clean electric generating fuel.

Fd like to show you a few slides:

[Strategy slide] A strategy to reduce ozone smog in the Northeast - faster and a: lower cost.

[Ozone slide] Ozone is caused as a by-product of atmospheric reaction of sunlight VOC, and NOx. It is a summertimR problem. Traditionally, the majority of the regulatory attention has focused on VOC control.

[Ozone Problem slide] O.-one is a persistent problem in the summertime wherever there are high population centers.

[Recent Events NOx Slide] But, recem events have shifted regulators' attention to NOx.

• The 1990 amendments specify that NOx should be treated like VOCs.

• Regulators must prepare SIPs by November, 1994 to demonstrate how they will attain the NAAQS air quality standards.

• The recent study by the National Academy of Sciences emphasizes the importance of NOx, and the potential gains toward ozone control that lie with NOx reduction. It therefore directed the Agency to focus more attention on NOx reduction strategies.

[3 ROM slides] Further attention was focused on Nox. after completion of the ROM studies by EPA. Last year, EPA finished Northeast regional modeling on a super computer in order to test the relative importance of NOx vs. VOC strategies. These slides show clearly that traditional EPA and state approaches - 75% VOC and 25% NOx reductions -- help, but do not solve the ozone problem. Reversing the approach to 75% NOx reduction and 25% VOC reductions makes an enormous difference!

[Pie Chan NOx Science slide] If NOx is such an important pollutant - where does NOx come from? TRANSPORTATION AND FUEL COMBUSTION. Tier I cars will emit 60% less NOx, and Tier • and California cars would push that to 80%. That leaves the NOx produced by the FUEL COMBUSTION SECTOR with the biggest unmet responsibility. 75% of stationary NOx comes from large electric utility boilers, and from the combustion of fossil fuels - coal, oil and gas.

[Bar Chart slide] The EPA RACT presumptions using low NOx burner technology for large electric utility boilers are: coal 0.5 lbs/mmbtu; oil 0.3 lbs/mmbtu; gas 0.2 lbs/mmbtu. Those limits were intended to be a floor, with states free to tighten the limits as needed to attain air quality standards. The glitch in regulation is that this low NOx burner technology standard creates a perverse result: the dirtiest fuel, COAL, is

041 allowed to emit 2.5 times as much NOx as the cleanest fuel, NATURAL GAS. Put another way, current standards discriminate against natural gas by requiring gas to meet more stringent standards than oil or coal.

IN UGHT OF THIS NEW DATA, IT IS IMPORTANT FOR STATES TO CONSIDER ADOPTING A LEVEL PLAYING FIELD NOx STANDARD OF 0.2 LBS/MMBTU »N THE SUMMERTIME FOR ALL GENERATING FUELS - GAS, OIL AND COAL EQUALLY.

This is especially important in the Northeast states under the Ozone Transport Commission. Such a proposal is similar to the level playing field concept in the Acid Rain Program where all plants receive allowances at the same emission rate. 0.2 can be achieved by natural gas with good combustion controls without SCR scrubbers; and gas deliverabiliry is easiest in the off-peak summertime. Existing coal and oil plants could cither s witch to burn natural gas fuel in the summertime without any new controls, or install proven technology. Remember that coal and oil plants can achieve a 0.2 level with the use of SCR, as well as gas. SCR is currently more expensive than burning natural gas, but it is an option available to the utilities that stands to benefit from improving technologies which lower costs.

[SIP slide) The regulatory elements of the proposed SIP rule would be:

• Applicability: Stationary Sources over 25 mw equivalent • Limit: Summertime: 0.2 lbs/MMBiu (24 hour average) Wintertime: At least equal to state adopted RACT levels • Summertime Period of Applicability: May \ to September 30 • Emission Trading: Contemporaneous trading only; Non attainment area-wide • Monitoring: Continuous emission monitors • Adoption Date: Within 6-12 months • Compliance Date: May 1,1995 • 1996

IT IS VERY IMPORTANT TO GIVE THIS STRATEGY AN EARLY PRIORITY TO OBTAIN THE GREATEST ENVIRONMENTAL QUALITY IMPROVEMENT, AND THE GREATEST OPPORTUNITY FOR IMPROVED ECONOMIC STABILITY IN THE REGION.

Lei's talk about costs: (Costs Chan slice)

5:1 CAPITAL/OPERATING COSTS: With a 0.2 Ibs/mmbtu standard, the annual cost of compliance to oil-buming plants will increase minimally because reside oil and gas fuels are generally priced comparably per MMBTU, and the same low NOx burner technology for oil works for gas.

For coal plants, gas is more expensive than coal, although plant modifications to switch to gas can be minimal, relatively speaking. Fuel switching from coal to natural gas achieves NOx reductions at Ihe low cost of $1000 per ton, while installing SCR technology for both oil and coal costs about $4500 per ton, according to slate data.

Applying a level playing field strategy of 0.2 Ibs/mmbtu would cut electric utility compliance costs by being far more cost effective that some of the SCR proposals now being considered. The economic and environmental benefits to the Northeast are potentially enormous.

(Benefits slide) • The 0.2 standard would achieve 180,000 more tons of NOx reductions in the summertime beyond EPA RACT presumptions.

• The potential for cost savings to the Northeast economy by avoiding the marginal VOC controls which tend to be very expensive to implement, (like California fuels), would be in the range of up to $5 billion annually, if marginal VOC tons cost $5000 - $10,000.

042 • The Clean Air Act is a zero sum game: more NOx reductions that are cheaper to achieve will offset VOC reductions that are more expensive. • Not only are these NOx tons cheaper, but based on the best science, they are likely to work 2-4 times more effectively to improve health levels. That's what the ROM studies suggest, and that's what needs to be verified by further modeling. The effectiveness of a NOx strategy will allow the Northeast to realize air quality benefits that otherwise would cost about $5 billion annually from a pure VOC strategy. This NOx strategy is over 10 times more cost effective than a strict VOC control strategy. This cost effective NOx strategy offers the potential to achieve clean air, sooner, at a lower cost to the economies of non attainment areas.

I: will be necessary for the PUC regulators to coordinate with the State environmental regulators in order to assure that the overall lower-cost clean air strategies are adopted.

(Relative Cost Advantages slide]

A level playing field NOx standard will also improve the market for cleaner natural gas by increasing the value of gas more than one dollar per MCE This increased value would reflect the inherent environmental benefits of burning gas -- instead of having to incur the cost of installing SCR controls. The higher value of pas would reflect the avoided cost of add-on controls. Gas combustion can meet the 0.2 standard by itself, with j'.aod combustion controls.

Tins strategy also creates a new summertime market potential of over 1 TCF of natural gas. That's in the Northeast region alone, hut the same science and economics also apply in the Southeast, Texas, and the Muiwest.

There arc other environmental advantages, as well. SO2, CO2 and air toxic emissions will also be reduced, and visibility will improve.

The 1993 AGA Enhanced Forecast identified the significance of "policy decisions that aggressively promote the environmental advantages of natural gas and rcnnwables in stationary and mobile applications." I can t think of any clean air initiative more suited to natural gas than state adoption of a NOx level playing field standard.

A Mimmertinie strategy improves the load factor of the pipelines and distribution networks, thereby improving the economic return of the gas pipeline and utility bases. It also forms the basis of a dialogue w nh the environmental community on the expansion of pipelines and distribution systems needed to improve dehverability.

Supporting this NOx strategy offers the gas industry a unique business opportunity to do good -- and do w ell Sound environmental protection, improved regional economies of the Northeast, and benefits to the utility and natural gas industries can all be achieved by placing a priority on cost effective, fuel-consistent NO\ reductions.

|Players slide]

IN SUMMARY, in the Northeast and other non attainment areas, a level playing field NOx standard that applies to electric utilities and other major sources would offer numerous benefits, including:

! Lower the risk of having to expend billions of dollars of refinery retrofit costs which will lead to much hither gasoline prices at the pump, in order to comply with a California Fuel VOC standard or other \ery expensive VOC strategy;

043 2. Establish a new market potential of 1 tcf for natural gas as a generating fuel in the summertime when pipeline capacity is available, which may also lead to a higher values for natural gas, reflecting its inherently cleaner nature.

3. Provide an opportunity for the environmental community, and the natural gas, refining and utility industries, as well as the Stale Air and PUC regulators, to work together to demonstrate environment leadership and promote a cost-effective clean air attainment strategy.

4. Achieve cleaner air, sooner, at a lower cost

Your support of this cost effective Clean Air solution will pay big dividends. This reformulation of State ozone strategies by adopting a level playing field NO* standard is BOTH environmentally effective to attain the air quality health standards, and a least cost compliance strategy for regional economies.

044 REMARKS OF PETER A. BRADFORD CHAIRMAN, NEW YORK STATE PUBLIC SERVICE COMMISSION BEFORE THE DOE/NARDC NATIONAL CONFERENCE ON NATURAL GAS USE BTU TAX PANEL

New Orleans, Louisiana April 26, 1993

From a regulatory standpoint, the concept of a BTU tax is multi-faceted. Of course, it would make lay job easier in some ways if Congress taxed something else. On the other hand, the recognition of some efficiency and security concerns will- reverberate positively in the debate over environmental externalities and will give a boost to DSM and renewable resources. The tax is clearly an operating expense. Operating expenses are clearly recoverable. If the tax passes on the schedule proposed, utilities will have ample time to file to recover in rates any portion that does not go through the various automatic adjustment clauses.

The Treasury Department has wisely sought comment on what seems to me to be the most dubious aspect of the BTU tax proposal from a regulatory standpoint — a requirement that state commissions flow it through or else — the "else" not yet being clear but being tied to the availability of other benefits. This process is referred to this as "normalization" but the George Orwell partisans among you no doubt realize that "peculiarization" would be a better word and would stimulate clearer thinking. It seems unlikely that the Treasury Department would be prepared to defend the need to "peculiarize" tax benefits or the BTU tax ratemaking treatment.

The practice of attempting to coerce state commission decision-making by holding consumers and companies hostage to the threatened loss of federal tax benefits has a discredited history of unfortunate side effects stretching back to the early 1970's. Before that, when the accelerated depreciation and investment tax credit provisions were first written into the tax laws, different state commissions adopted a number of different practices. Some flowed the benefits immediately through to consumers by allowing utilities to charge customers only for their actual taxes; others adopted ratemaking treatment designed to allow utilities the benefit of timing differences but not the benefit of the actual tax reductions? still others permitted the utilities to keep the actual tax benefits for their shareholders.

Because utilities take on a franchise obligation to render adequate service in return for their monopoly status, they have a duty to make the investments necessary to the provision of

04 5 -2-

adequate service. Consequently, the justification for extending to them benefits designed to encourage capital investment in other sectors of the economy was always open to question. Indeed, to those persuaded to the view that utilities already had incentives to pad their rate bases,-^ the creation of tax incentives toward the same end was a serious policy error. Despite the fact that the Republic was still flourishing, the Congress allowed itself to be persuaded that those states who were flowing the benefits through to consumers were thwarting important national policies and should be stopped. New legislation declared that any utility ordered to flow the benefits through to consumers would lose the right to take the benefits at all. For a time, all of the states then abandoned flow-through policies.

Especially with regard to the investment tax credit, the interests or shareholders and consumers began to diverge.-^ Actual utility earnings began vastly to exceed earnings for ratemaking purposes. For shareholders, the most capital-intensive approach to power supply appeared to be the most profitable. For consumers — we now know — the less capital-intensive solutions such as energy efficiency would have been preferable. This masterpiece of federal misunderstanding is a significant flagstone on the pathway to nuclear construction fiascos that we will be paying for for the rest of our lives.

Ironically, the financial difficulties that these tax policies — through their incentives to construction — helped to create for the utilities then became one justification for continuation of the policies. It was argued that the financial hardships that the utilities were facing in the late 1970's could only be alleviated by continued federal adherence to tax policies designed to support construction. In the end, the problems of nuclear construction produced cost overruns so large that decisions designed to benefit shareholders rather than consumers wound up hurting both.

—' For example, the "A-J-W effect" discussed inter alia in Alfred Kahn, The Economics of Regulation. Volume II, pp. 49-59. Kahn feels the tendency is "limited" and may do more good than harm (p. 59), but this assessment was written in 1S71 — before most of the negative experiences with power piant construction in the electric sector.

—' This problem and its history are well analyzed in a paper delivered by Dr. Charles Stalon "On Why State Regulators Should be disturbed About Current Federal Utility Tax Policy," Proceedings of the 94th Annual NARUC Convention. 1982.

046 -3-

Phase I of these ill-considered federal experiments with mandated ratemaking came to an end in the very legislation that ushered in Phase II — the Tax Reform Act of 1986. In the last stages of the consideration of that complex legislation, a provision was introduced by Congressman Robert Hatsui — who later courageously acknowledged that it had been a mistake — that forbade state commissions from promptly passing back to consumers the excess cash held by utilities who had collected it on the assumption that it would one day be paid at the 46% federal tax rate. Since the '86 Act lowered the tax rate to 34%, these reserves were excessive, and billions of dollars could have been returned to consumers. It was bad enough that the Congress enacted this legislation without hearings and without understanding what it was doing. What was even worse was the Treasury Department's behavior in the following years, in which it defended this provision by arguing that state regulators could not be trusted to return the money to consumers in ways that would not be harmful to needed utility construction programs. In opposing this result the Treasury Department traded off the certainty of several hundred dollars worth of harm to every American family against the speculation that a few unnamed state commissions would for unidentified reasons do harm to utility construction programs that were by then minuscule in comparison to the programs of the 1970's. Thus some utility lobbyists wer*s again successful in parading the myth of vampire consumer intervenors and spineless state regulators before breathless federal officials. If there is a small silver lining to Phase II, it is that these reserves — not having been returned to consumers when they should have been -- are at least now available to cushion any increase in the corporate tax rate that may come out of the current Congressional deliberations.

The present BTU tax flow through proposal is flawed in some new respects. For one thing, the BTU tax has absolutely nothing to do with the other tax benefits that would be withheld were the tax not passed through. Thus, the amounts that would be withheld on the one hand have nothing to do with the BTU tax amounts on the other. Furthermore, the consumers and the companies would be the innocent victims of this foolishness, for they are not refusing to pay the BTU taxes.

Secondly, the proposed penalties are completely unnecessary. Few aspects of regulatory law are more basic than the proposition that taxes are a legitimate operating expense. Not only that, but taxes on fuel are likely to be collected through the fuel adjustment clause, without even a rate case.

047 -4-

The only context in which a utility might be unable to raise rates to reflect the new taxes would be a situation in which the utility's earnings were excessive for other reasons. Even here, the adjustment clauses would pass much of the tax through. However, the utility would be unlikely to file new rates at a time when its earnings were for other reasons so ample that the net result might be a rate decrease. There is no reason for the Treasury Department to be protecting utilities - in this c i rcumstance.

Finally, the mandated flow-through of the tax to end users has at times been defended with vague rhetoric about the need for end users to feel this tax in order to maximize their incentives to conserve. In fact, efficiency concerns are unrelated to the flow-through of the tax. To the extent that energy efficiency and security are goals, they are almost certainly maximized by moving the tax as far upstream as possible. That way it will pass through the maximum number of transactions and industrial operations. It will stimulate energy efficiency in the places where that course is cheapest, whether by the end user or by those along the way.

There may be other good reasons for moving the tax further downstream. For example, such a course may facilitate collection or minimize overlap with producing or consuming state taxes. I don't pretend to know enough about taxation or tax politics to be confident as to where the proper collection point is, but efficiency concerns don't push that point downstream.

It is to Treasury's credit that they have sought comment on the mandatory flow through proposal. As the historical review shows, this course of conduct is unnecessary and has a way of giving rise to unintended and unfortunate consequences, some of them painful to the most avid original proponents of the measures. It will be even more to Treasury's credit if they abandon this aspect of the BTU tax entirely.

048 BTU ENERGY TAX LEONARD L. COB0RN ACTING DIRECTOR OFFICE OIL AND NATURAL GAS POLICY O.S. DEPARTMENT OF ENERGY I. TAX PART OF ECONOMIC PACKAGE o Energy tax is part of a package and should be evaluated in that perspective and not in isolation o Economic package's second largest revenue raiser is the energy tax. Overall, economic package will lead to o Deficit reduction o Lower interest rates o Increased investment o Increased productivity 11 . GOAL, OF TAX

o Primary goal of tax is to raise money o Raises about S31-33 billion per year when fully phased in starting in July 1996. The net amount is about $22 billion per year. o Over the first five years of the tax, it raises about $70-71 billion o Other goals are important but subsidiary to the revenue goal. The other goals include o Conservation o Environment o National security — lowering oil imports III. BTU TAX IS BETTER FOR GAS THAN THE ALTERNATIVES o Among the alternatives, ad valorem, carbon, level BTU, gasoline, and import fee, the Administration's BTU tax with a supplement for oil is better for gas.

o Interstate Natural Gas Association of American (INGAA) study shows this version of the BTU tax with an oil supplement reduces gas demand less than any other tax except for a gasoline/diesel tax. o INGAA study also shows that residential prices go up less for gas with this BTU tax than all other energy taxes except for a gasoline/diesel tax.

o This tax takes away the bite on natural gas that would come from a level BTU tax, an ad valorem tax, or a carbon tax. IV. BROAD BASED TAX CONCEPT o This BTU tax introduces the idea of a broad based tax on consumption o Unlike the Value Added Tax (VAT), this tax produces more revenue, more quickly and with less administrative cost. o Alternatives under discussion, such as a VAT, are costly to administer. A VAT would require a bureaucracy abut the size of the Internal Revenue Service and would take about three to five years to put into place. Need for revenue is more urgent. V. IMPACT ON INTERNATIONAL COMPETITIVENESS o Impact on international competitiveness is low o Energy costs even after the imposition of the tax are lower in the U.S. than in other G-7 nations except Canada. o Exemptions for energy exports will maintain parity with other countries. VI. GAS PASS THROUGH o Is the gas pass through issue real? Is normalization necessary? o The discussion about these questions leads to the conclusion that they are a smoke screen for other, more important issues, such as, whether local distribution companies will be exposed to rate proceedings and rate adjustments, especially in light of lower interest rates . o If this is the real issue, then perhaps we should drop the controversy and move on to more important issues.

050 GAS COULD HAVE FARED WORSE

Other tax alternatives harder on gas demand Only a motor fuels tax would look better for natural gas This version of a Btu tax takes away the bite on natural gas that would come from a level Btu tax

Impact of Alternative Taxes on Natural Gas en Demand by 1997 Motor Admin Ad Carbon Oil Import Level Fuels Btu Valorem Tax Fee Btu

0°/c -1.1% -1.40/0 -2.3% RANKING OF TAXES BY FUELS

Natural Gas Oil Coal

Best Motor Fuel Level Btu Oil Import Fee Admin Btu Carbon Tax Motor Fuel

JI c VAT Motor Fuel VAT Carbon Tax VAT Admin Btu Oil Import Fee Admin Btu Level Btu Werat Level Btu Oil Import Fee Carbon Tax THE LAW OF UNINTENDED CONSEQUENCES DOE/NARUC 2nd Annual Conference New Orleans, LA April 26, 1993

Remarks by Michael Baly HI

Thank you Chairman Bradford, and thank you Ken Malloy and Paul Rodgers for inviting me. On behalf of the members of the American Gas Association, and on behalf of many American consumers I would like to talk today about a law that is of particular concern to the natural gas industry, and should be of concern to this audience. It is not a law that has been passed by Congress or signed by the President. But it is a law that could come back to haunt them.

It is the law of unintended consequences -- a law that we believe will quickly go into effect if the proposed 3iu tax is enacted and if the proposed collection point for this tax -- at the city gate -- becomes a reality.

It is because of the law of unintended consequences that we oppose both the Btu tax and the collection point chosen by the Treasury Department. I hope a few examples will prove my point.

We do not believe the Btu tax was intended to be unfair, or hardest on the poor.

Yet in reality the tax is regressive. Both directly and indirectly the costs will fall disproportionally on low- and middle-income consumers. The direct impact will be higher utility and transportation costs, which will obviously hurt the poor the most. They spend a much higher share of their disposable income on energy than do the rich. And while there are provisions to help offset the impact on poor households, the middle-class will feel the full burden of this tax.

We estimate that the average bill for a natural gas heated home could increase by about $25 a year, while total energy costs including electricity and gasoline, will increase by about $124 a year.

The inflation-based indirect costs of the tax only make this inequity worse. Literally nothing can be produced or manufactured without energy, so when you raise the price of energy, you raise the cost to manufacturers, who pass that cost on to consumers. We estimate that this indirect cost will add another $184 to a typical household's annual energy bill. The total added cost of this tax amounts to about $310 a year.

05,'i We do not believe the tax was intended to be regionally inequitable. Yet the Btu tax penalises different regions of the country for their weather patterns in the form of higher heating or air conditioning bills.

We do not believe the tax was intended to hurt the economy. Yet by adding to the cost of manufactured products, it hurts U.S. competitiveness in our increasingly global economy.

Nor do we believe the tax was intended to increase spending. In fad the tax is supposed to reduce the deficit. Yet raising the price of almost all American goods results in inflation, which leads to an increase in the cost of all government entitlement programs that are keyed to the consumer price index. That means more government spending, which is not the way to reduce the deficit.

More important, all economists agree that the best deficit fighter of all is a healthy economy. If this lax hurts the economy by slowing down the recovery, it could worsen - - not lessen -- the deficit.

We do not believe this Btu tax was intended to hurt the natural gas industry. On the contrary, originally an energy tax was supposed to promote energy security and environmental goals -- both of which would be to the advantage of clean-burning, domestically abundant natural gas. President Clinton made the increased use of natural gas one of the four major planks in his energy program, and parts of his economic plan call for funding programs that would also increase natural gas use.

Yet the Btu tax - and in particular the proposed collection point at the city gate - could seriously hurt the natural gas industry.

First of all, raising the cost of natural gas and other energy could drive manufacturing companies out of the country. The natural gas industry would lose customers and the country would lose jobs.

Second, the higher supplemental tax for fuel oil - a surcharge meant to improve the environment and reduce oil imports - has been eliminated for residential heating.

Third, the fact that ethanol and methanol have been exempted from this tax hurts natural gas, especially in the natural gas vehicle market - a market that the Clinton administration has repeatedly said it wants to see grow.

Fourth, the Btu tax could raise the retail cost of natural gas by a larger percentage than the retail cost of electricity - particularly in the commercial and industrial sectors. This could result in natural gas losing market share to electricity - most of which is generated by dirtier and less reliable fuels.

054 This too is the opposite of the C|;nton Administration's intention to reduce oil imports and cos! use, in favor of natural gas.

But it is in the area of the collection point that the law of unintended consequences really takes effect, because if the tax is paid at the city-gals -- out of the pipelines, it could put many gas companies - especially gas utilities -- in financial jeopardy. It could also adversely affect a utility's ability to transport gas to its customers.

We are quite sure neither of these two outcomes was intended. Yet if public utility commissions delay passing this tax through to the ratepayer, then the utility - in particular the shareholder -- will have to absorb the cost. Given that the added costs of the tax could equal or even exceed the annual net incomes of a majority of gas utilities, it is easy to see how this tax would put the utility in dire straights financially.

The tax could also exceed a utility's utility's transportation margin. Again, if the PUC did not promptly allow the utility to pass the tax on to its large commercial or industrial customers, some companies may have to cease transporting gas to them.

There is also the problem of hidden taxes. When taxes are piled up -- one on top of the other -- the later taxes are based on percentages of the original cost plus the earlier taxes; i.e., the State of New York gross receipts tax is 5.61% and 2.35% in New York City. Additionally, up to 8.25% is added to this as a sales tax. These piggy back taxes result in much higher -- and very unfair -- out-of-pocket costs.

And rest assured that disputes will arise over who must bear the costs of uncollectible taxes.

In fact, disputes among the utilities, their PUCs and the U.S. Treasury are bound to arise over this entire collection process. Who ultimately gets to decide the fate of this tax? Quite possibly the courts, which will be expensive, time-consuming -- and unintended.

On this last issue -- the dispute over the collection point - the administration agrees that the tax should be passed through to the end-user, and it has even fired a "shot across the bow." But from the gas utility's standpoint, the shot was aimed at the wrong target. The Clinton administration has said that if the PUCs do not allow utilities to pass the cost of this tax through to the ratepayer, then the utility will lose its tax benefits under normalization.

Talk about your unintended consequences. In effect, the Treasury Department is saying to the PUC, "pi it down that hammer you are going to hit the utility with, I will hit the utility myself!"

055 In other words, the utility could wind up getting hit twice under this proposal - once in the absorption of the tax and again in the denial of normalization benefits.

For these reasons and many others, we beiieve that if a Btu tax must be imposed, it should be paid by the end-user snd collected by the seller - whether it is the utility, producer, the pipeline or the marketer. Much like the federal excise tax on our monthly phone bill, this would take advantage of an in-place collection mechanism, thereby eliminating payment problems and administrative problems., as well as many of the other problems I have just mentioned.

It would also allow the utilities to list this tax separately on the bill they send the customer, making it clear that this added cost is a federal tax, not a rise in the price of natural gas.

Granted, some in Congress may be reluctant to see the Btu tax appear on the customer's bill. But many PUCs may require such disclosure regardless of where or how the tax is collected. And one way or the other, gas company executives will be compelled -- and rightly so -- to remind their customers that their higher bills are a reflection of this federal tax, and not of anything the gas company has done. After all, why should utilities be held responsible for a tax they opposed in the first place?

Today we are working very hard to get the collection point moved because we feel it would be better for customers, regulators and gas companies alike. We believe we will be successful in this campaign. However, if we are ultimately unsuccessful, we hope regulators recognize the intent of this tax, which is to increase the cost of gas. It therefore should be treated as such, qualifying it for a purchase gas adjustment.

To conclude, the American Gas Association is entirely in agreement with the Clinton administration's attempts to put our nation's fiscal house in order. We are willing - - in fact eager -- to work with the White House and Congress to produce a sensible economic package that meets the president's goals of reducing the deficit, promoting economic recovery, and increasing this nation's use of natural gas. A fair tax that is easy to collect is both the key to these goals and the key to public acceptance.

We believe that the energy tax as currently proposed hampers deficit reduction efforts, hinders economic recovery, inhibits the use of natural gas and - as we have seen from the growing aversion to this tax in public polls - hurts the chances for public acceptance. If it becomes law, the law of unintended consequences will soon go into effect as well.

Thank you for being an attentive audience. [:private\wp\btuiax

NARUC DOE Conference New Orleans April 26, 1993

Remarks by Chuck Jordan Cambridge Energy Research Associates

The Clinton BTU Tax Proposal

I'm surrounded on this panel today by four individuals that represent very obvious constituencies — they will be presenting the Administration's modified BTU tax proposal and a critique of its shortcomings (in their view).

They arc not wrong —just biased — and justly so. That's what makes the process work.

What I propose to do this morning is present on objective view of (he principles and factual impact of the proposal as it stands today, or

Establish a base starting point for this morning's discussion, so to speak.

I will qualify my objectivity only to the extent that I am personally biased in favor of natural gas

1 am going to address five points this morning

1. How does the tax impact on each of the primary energy sources

2. What other factors must be considered

3. The impact of the lax on gas versus coal — one of the primary competitors to natural gas

4. The alternative taxing mechanisms

5. And where is the proposal going from here

First let's review how the proposed tax would hit each energy source — at least in theory.

Two of my colleagues at Cambridge, Bill Durbin and Dan Yergin, published a private report for our clients in February that started out with an analytical review of the original Btu tax proposal

The Administration's proposal, at thai time, would generate the following revenues:

057 Estimated Gross Annual Revenues (at full phase-in) (Billions of Dollars)

Crude Natl Nu- Non-fuel Oil Gas Coal clear Hydro Use Total 21 5.6 5.2 1.6 0.7 (3.) 31

• non-fuel use means Payback Credits for feedstocks and exports

This analysis assumed a 100% pass through to end users and noted that tax credits — primarily for low-income families and to a lesser degree for feedstocks and exports of crude products — would reduce these revenues by $10-12 Billion.

Natural gas would bear a 26 ceni/MMBTU load but the overall analysis indicates it would fair slightly better than coal — its primary competitor in the electric power generation market — especially in new capacity additions.

Crude oil and products, of course, would get trounced.

But my colleagues' most telling conclusion was the phrase "The Devil's in the details" — and that has proven to be true.

First of all let's look at what outside factors — so to speak — might impact these dollars — or more appropriately, who will really pay them.

Market dynamics will certainly play a role:

— The tax on crude oil is more than twice that of other fuels.

— But oil products will demonstrate varying abilities to pass the tax through to end-users.

— In the case of diesel and jet fuel, there are no short-term energy alternatives.

• They will experience full pass-through to the end-user.

• The modified proposal, of course, now exempts jet used on international flights.

— As one moves down in a product's ability to pass the tax through, we find the same lack of immediate alternatives for home heating oil, but:

« Personal conservation could reduce demand (and revenue)

• And the new exemption of the surcharge will reduce the consumers' burden substantially.

— Gasoline will have a problem with full pass-through:

• Because of overcapacity, we believe some refiners may have to eat a portion of the pass-tlirough

— And finally HSFO — Since this product competes directly with natural gas, and, for the most part, untaxed bunkers, there will be little opportunity to pass the tax through to end- users.

053 • All in all, this tax would put increased pressure on the less efficient or less flexible refineries.

• A subset of the market impact affect will be the collection point effect.

• The further upstream the collection point is placed, the better chance of the full impact not flowing through to the consumer.

How will natural gqs fart; versus coal

— Both energy forms suffer less under a BTU lax than they would from a carbon tax (more later).

— The most adverse impact of the tax will be the stepping up of DSM programs by utilities (both electric and gas) plus the regulators.

— Even without a tax we anticipated DSM programs to depress demand increases for natural gas over the remainder of the 90's.

— Therefore, tl.: tax is a very serious threat to natural gas and coal that will more than offset some of the emerging deficiencies in DSM programs such as true quantification of benefits versus costs — and difficulty in measuring externalities.

— On balance, however, natural gas will marginally beat coal on a hcad-to-hcad basis.

— Natural gas is more BTU-cfficicnt in generating KW's of electricity.

• In relatively new existing facilities: • Gas-fired units require 7-8 thousand BTUs to produce 1 kWh • Coal-fired units require 9-10 thousand BTUs Therefore, gas will be 25-30% more efficient, thus giving it the edge in generation of electricity

• In state-of-the-art facilities: • Combined cycle gas turbines require 6,300 BTUs to produce 1 kWh • Pulverized coal with stack gas clean-up requires 7,800 BTUs This finds'gaps to be 20% more efficient

• Therefore, the floor price for natural gas would rise relative to coal and make natural gas more attractive to utilities.

• This may be exceptionally significant with the Clean Air Act Phase II decisions facing the utility executives.

• In addition, the ceiling price buffer that residual fuel oil normally provides for natural gas will go up corresponding to its oii surcharge pass through.

• Also, should the natural gas collection point placement allow less than 100% pass through, natural gas will look more attractive to end-users; therefore a rise in demand will result vis a vis coal.

Now let's step back to President Clinton's basic objectives in selecting a BTU tax as his primaiy taxing vehicle for energy.

059 He had three objectives:

— Fairness

— Envirotonenlal correctness

— Revenue generation

Has he accomplished his objectives?

— Fairness

• This is in the eye of the beholder.

• There are an increasing number of regional and individual disparities as (he exemptions unfold.

• The crude oil segment of the energy industry has been singled out for discriminatory treatment.

• And the administrative burden will hit certain segments harder than others.

• However, on balance, it is the least controversial of the energy taxes proposed — and the least risky, politically, for Congress.

• Although not a carbon tax, (his represent.1, the first across-the-board U.S. energy tax.

— Environmental correctness

• Again, it hits crude oil and oil products exceptionally hard — even though, as in the case of new reformulated gasolines, great strides have been made in improving environmental efficiency over the last decade or so.

• One must also question the near equivalency of the tax on natural gas vs. coal on an environmental basis — especially given the Clinton/Gore pre-election commitments to natural gas and cleaning up the environment

• But, in general, the tax may reduce energy consumption which would support the environmental greening of the U.S.

• Therefore it could be environmentally effective.

— Revenue generation

• The original proposal was estimated to generate a net of $21 billion.

• Therefore this appears to meet President Clinton's revenue generation objectives.

— It now appears that the Tax Policy in the Department of Treasury made a significant underestimate of the revenue-generation capability — of about $12 billion.

050 — This underestimate is being used to rationalize and offset the credits or short-fall that new exemptions arc creating.

• What if the BTU tax fails — or is removed from the Omnibus Budget Reconciliation Act due to the weight of its political baggage?

• What would be the unpact of the alternatives?

• To generate the $33 billion of gross revenue, the contribution breakdown of the popular alternatives would be significantly different:

Gross Revenues ($billions/year)

Oil Gas Coal Total

A Carbon Tax @ $20/ton 15 7 12 34

A Gasoline Tax @ $0.30/gallon 33 — — 33

An Ad Valorem Tax on Energy @ 14.5% on first sales 22 « 4 34

Carbon Tax

— Would give natural gas an advantage vis-d-vis coal and oil.

— Would have the insidious result of painting fossil fuels as "bad" and set the groundwork for future attacks on fossil fuels in general.

— Political reality is that Senator Byrd will not let this tax concept out of the box due to the impact on the coal industry.

— The political reality point could also apply lo an import fee which would come down hard on the Northeast home heating oil users.

Gasoline Tax

— The gasoline tax may appea! to some industries that want to totally exclude their commodity or product from contributing to the cause — however, it would have an extremely large and visible impact on consumers — and, given the political trauma of a 5 cent increase in 1990 — it won't succeed.

— Il is considered too regressive and loo politically imbalanccd across the broad spectrum of states...and would go too far beyond the bounds of fairness to fit President Clinton's public pronouncements.

Ad Valorem

• This would also be loo regressive and. for the most part, not generate environmental benefits. (Impact on coal is minimized).

OSl • The impact on consumers would be exaggerated during times of price volatility.

• Therefore, of the alternatives considered, the BTU tax proposal still appears to be the most politically acceptable.

But what about the new and ever-changing Modified BTU Tax Proposal? What has it done?

• It has — and is continuing — to challenge the Administration's first principle — fairness.

• 13 exemptions have been added and more are under discussion

• A few of these, such as the exemption of exported fuels and jet fuel use in international flights, appear to make some sense.

• However, the Administration's basic principle of fairness appears to be crumbling in light of compromises by the Administration.

• We can see a scenario where this could ultimately spell defeat for the BTU Tax concept as it winds its way through the legislative processes.

• The modified proposal also begins (lie process of manipulating the collection point.

• It didn't take long after the original proposal was issued before (he sharp pencils began to figure out how to make other segments cat larger portions of Ihe tax and bear larger amount of the administrative burden.

• One would think

• The most elegantly simple solution is the line-item surcharge on the end-user's bill.

• The modified proposal does indeed signal a change in the Administration's position of shielding the consumer from the tax and encouraging full pass-through. It now appears that consumers will ultimately see the line item on their utility or transportation bills.

• With respect to the principle of favoring the environment, the modified bill also backtracks significantly.

• Certainly the exemption for home heating oil violates the principle.

• And the new proposal undercuts the original position of natural gas to some degree by creating such a broad category of exemptions.

• This cost disadvantage will increase the attractiveness of DSM programs and dampen demand.

• With respect to revenue generation, one can only say that the Administration's claim that the exemption revenue loss has been offset by an original underestimate of collections means:

• This demonstrates thai the true revenue impact cannot be effectively calculated.

In summary, the impact of the BTU Tax Proposal will be varied:

062 It will indeed generate a significant amount of Uie revenue required — while demonstrating by its very character how pervasive energy is for the whole US economy.

Conservation programs — in the form of demand side management and integrated resource planning — will gain in relative cost competitiveness against traditional fuel sources in power generation use.

On balance, however, overall fossil fuel demand is unlikely to be significantly impacted.

The competitive advantage of BTU efficient technologies will widen marginally as a result of the tax — particularly for natural gas powered generation capacity.-

Interfuel competition may result in the tax not falling uniformly — gasoline, for instance, may carry more of the oil tax share to the consumer as compared to, say, high sulfur resid.

The true fairness of the tax cannot be judged until the final version is passed and signed into law — and as with similar legislation in the past — perverse consequences will call for subsequent corrections.

Again, the Devil will be in (he details.

Perhaps the most significant point to make is that successful implementation of this discrete tax on energy opens a door that — in all probability — will never be closed. It is simply too lucrative and too environmentally justifiable to ever go away once it is established.

And finally, the concept of a BTU Tax has all other alternative forms of an energy tax beat — while one logically expects to sec it prevail, it may eventually be subsumed in an even larger discussion about a national value-added tax to finar.ce a national health care program.

063 REFLECTIONS ABOUT STATE POLICIES IN A POST-ORDER 636/ENERGY POLICY ACT ERA

at the NAR0C-DOE NATIONAL CONFERENCE ON NATURAL GAS DSB New Orleans, Louisiana April 26, 1993

by Frank O. Heintz Chairman Maryland Public Sorvico Commission

A recent edition of Fortune magazine was about dinosaurs. The dinosaurs were three American companies which were very successful in the 1970s but turned into big losers in the 1990s. The dinosaurs are IBM, Sears, General Motors. In the 1970s these companies made billions of dollars. In the 1990s, these companies are losing tens of billions of dollars.

According to the article, the throe companies didn't respond to significant changes in their environment. They failed to understand the increasingly competitive market in which they were operating. They failed to take into account changes in technology and customers' needs and preferences. They hung on to the old modes too ?ong and were overtaken and overwhelmed by the new. IBM, Sears and General Motors are but the most recent and attention getting examples of the dinosaur syndrome. But the historic landscape is littered with countless examples of companies and industries which have been overwhelmed by change.

I should emphasize that not only can businesses succumb to the dinosaur syndrome, but also institutions, governmental agencies and individuals. Any person or organization which fails to take into account a new environment or a paradigm shift can quickly find itself in serious trouble. The gas industry is in the midst of a paradigm shift or sea change from regulation to competition. Therefore the heart of this conference might be the following rhetorical question: Are there dinosaurs, or emerging dinosaurs, among us? For example, Are there producers who have not positioned themselves to survive through widely fluctuating commodity prices? Are there pipelines wistfully recalling

064 the glory days of bundled merchant sales? Are there local distribution companies operating under the misperception that their franchise protects them from competition? Are there consumer advocates harboring the hope that the rates of weather-sensitive, residential customers can be subsidized by industrial customers? Are there industrial customers who want to take LDC gas supply at their own discretion, while expecting the LDC to always be available as a supplier of last resort? Are there state regulators who believe that past regulatory policies and procedures will be suitable for the 1990s? If the answer to any of the questions is "yes", then beware of the dinosaur syndrome.

At this moment ar.y of us in this room may be growing a dinosaur tail. We ma^ be in danger of being overwhelmed by the tidal waves of change affecting America's energy industries. First, there is the danger that we will not perceive the changes. Second, there is the greater danger that we will try to ignore the new realities. Third is the greatest danger that we will lack the will to change and adapt.

As a result of wellhead deregulation, pipeline open access and Order 636 restructuring, we have entered a new era for the gas industry in which competitive market forces are strengthening and regulatory controls weakening. The competitive dynamics of the industry will continue to expand and the regulatory regime will continue in retreat. The long term trend is clear - competition will increasingly supplant regulation.

Importantly, wherever competition emerges, the future for service providers and consumers becomes harder to predict. Competitive markets do not respect long range plans of corporations or government agencies. Nor do they abide by the predictions or expectations of consultants, planners, futurists or a regulator giving a speech. Competitive markets synthesize and respond to an array of crossing-cutting forces and influences. Therefore, in the competitive 1990s era, companies, consumers and regulators should, at all times, be ready for the unexpected.

For an illustration of unexpected consequences, let's look at competition at the wellhead. Beginning with the Natural Gas Policy Act and ending with the Wellhead Deregulation hat, the gas patch experienced a thirteen year transition from blanket regulation to unfettered competition. As the process began, the conventional wisdom was that the gas production industry would experience good times. Indeed, many consumer advocates feared that wellhead deregulation would bring about a massive income transfer from consumers to producers.

065 The actual results were far different. The price of natural gas did not rir.e precipitously. During the gas bubble, which became the gas sausage, consumers were the beueficiaries of a buyers' gas market. The price of gas was so suppressed that more than one half of the independent producers vrere driven out of business. The whole production industry experienced a recession and retrenchment. Ir my view, we should enter the post-Order 636 and post-Energy Policy Act era with two principles in mind: First, competitive market forces will prevail over incompatible regulatory policies. Second, competitive market: dynamics will be, more often than not, hard to predict and will have consequences which will defy conventional wisdom.

The post-Order 63 6, post-Energy Policy Act era will have several key characteristics. Here is my list of eight characteristics of the 1990s. First, change will accelerate. Knowledge and skills will have to be upgraded more quickly. Modes of thinking will have to change mora rapidly and decisions will have to be made and executed more expeditiou3ly. Sficond, competition will continue to intensify. In the energy industry competition will intensify among gas providers, among energy sources, and between supply aide and demand side alternatives. Third, technological innovation will quicken. Changes in technology will rapidly alter the production, delivery, use and conservation of energy. Rapid deployment of new technology will greatly effect patterns of production, delivery and use of energy. Fourth, environmental policy w:\ll increasingly determine energy policy. The production, delivery and use of energy will be shaped by society's emphasis on protecting the environment. Fifth, energy efficiency and conservation will ba increasingly integrated in'o the business of supplying energy. Customers will expect it, government policy will require it, and businesses will come to regard it as part of the menu of services to be offered along with energy supply. Sixth, the energy marketplace will become increasingly segmented, requiring differentiated services. Mo longer will it be sensible to make decisions in terms of broad customer categories such as residential, commercial and industrial classes. The consumer case will increasingly be characterized by niche and segmented markets, each with its particular preference for price, reliability and customized or added-value services.

OOfi Seventh, energy providers will increasingly diversify into related service offerings. In order to address the needs of segmented and niche markets, energy companies will have to offer a variety of packaged and unbundled services regarding energy supply, energy conservation, sale or leasing of end use equipment, and servicing of end use equipment. Eighth, the Most important aspect of the new era is that gas companies will be customer driven. As never before, the energy business will have to focus on customer satisfaction. The gas industry will have to understand and respond to customers' needs, preferences and expectations. Intense customer focus will be imperative to success.

The subject of this conference — state regulation and market dynamics following Order 636 and the Energy Policy Act — is essentially a forum for discussing how to respond to these eight ingredients of the new era. The Energy Policy Act will intensify competition among all energy sources, on both supply side and demand side. Order 636 restructuring will increase the competitive gas market dynamics, make new options available to gas consumers and force changes in the roles of industry companies and state regulatory commissions.

Many of the consequences of Order 636 are already identifiable. Order C3 6 brings to an end the decades-long era of pipelines performing the aggregation and swing supply functions. It forces upon LDCs new responsibilities for supply acquisition and transportation. Unbundling of pipeline services will proliferate the options available to both local distribution companies and to end users who wish to take into their own hands the responsibility for acquiring, transporting and storing gas.

However, we must acknowledge that there are many consequences of Order 636 which are difficult to predict at this time. Will a robust market for released firm transportation and storage capacity come into existence? What will be the dollar value of the released capacity? What will happen to interruptible transportation vis a vis released firm capacity? Who will be the successful aggregators in the new, restructured environment? How user- friendly will the new unbundled world be? Will transaction costs go up or down? Will new efficiencies result?

One certainty aft^r Order 636 is that the role of the local distribution companies will increase in both importance and complexity. For the next few minutes let me focus my remarks on LDCs, the gas supply function, market threats and

OS* opportunities, and thf> new era of competition and customer satisfaction. The most immediate challenge for LDCs is to carry out their expanded post-Order 636 role of buying, transporting and selling gas. In order to be successful aggregators and merchants, LDCs will need to beef up their capabilities for managing gas supplies. Due to the complexity of options for purchasing and transporting gas, X anticipate that most LDCs will have to increase the size of their gas supply departments. But increasing the size will be less important than assembling a very astute and well informed staff that has the talent to devise a sound overall gas supply strategy and the tactical savvy to successfully execute the strategy.

The LDCs will have to upgrade their computer and telecommunications network. The computers will be needed in order to undertake sophisticated modeling and analysis of demand behind the citygate and supply options upstream from the citygate. Data management must be combined with a telecommunications network which will provide the supply department with more real time information about the price and contract terms for gas supply options and transportation routes. As a consequence of Order 636, I foresee the eventual emergence of six to twelve large aggregator/marketers to serve medium-sized and smaller LDCs. Most will be separate subsidiaries of producers or pipelines. Some will be independent marketers. What will distinguish these new aggregator/marketers will be their ability to use information.

The dozen or so top aggregators will develop the sophisticated information data base and electronic network which is necessary to make astute decisions about buying, selling, transporting, and storing gas. Their data base and real time information will equip them to effectively coordinate the many pieces of the unbundled pipeline system. At any point in time, they will be able to identify the best-cost way to package the acquisition and delivery of gas to a wide variety of customers.

These super aggregators will be especially accomplished at obtaining and synthesizing information and making decisions which maximize the potential gain and minimize the potential risk. They will have an in-depth knowledge of supply, transportation and storage options. They will learn how to win and retain a portfolio of customers whose load profiles complement one another. After Order 636, the winning breed of aggregators will be those who learn fastest, have the best information, outthink the competition

OSS and are continually shifting through the maze of information for signs of new opportunities to be pursued and new risks to be avoided or minimized. The threats to LDCs market share are wrll known: other energy sources such as electricity, oil and coal; conservation and efficiency; other gas suppliers; bypass, when industrial customers connect directly to pipelines; new electricity applications; and, relocation of industrial production. There are market opportunities for LDCs which we will be hearing about at this conference: gas-powered space cooling; natural gas vehicles; electric generating stations; packaged cogeneration of electricity; other new snd uses for gas; integrated resource planning and fuel substitution for reasons of energy efficiency or environmental protection; added-value services; and, energy-related services.

Why do I list the market threats and opportunities for LDC? Partly out of a concern for LDCs. But more because of my concern for residential customers. 1 hold this view. It will be beneficial to consumers if LDCs are permitted and encouraged by regulators to meet market threats and to seize market opportunities. Why? Because an LDC reduced to serving only residential customers will be a high-cost service provider. An LDC maximizing throughput can lower the common costs borne by residential consumers. LDCs that improve their load factor can reduce gas supply costs for residential consumers. Finally, LL>Cs which are competing for discretionary markets are more likely to be focusing on matters of efficiency and responsiveness to customers.

To reduce market threats and maximize market opportunities, LDCs must become increasingly customer focused. Successful LDCs will think in terms of customers, not ratepayers. "Ratepayers" is the old mind set connoting captive customers who exist to pay monthly bills and are bound to take gas service from the local distribution company. The term "customer" denotes the need to win and retain end user.: by means of providing a superior value of goods and services to the customers.

The nature of tha LDC customer base will continue to change. The niche markets within the customer base are already many and will multiply in the future. In order to retain and win customers, the LDCs will have to respond to the niche-market characteristics of their service territory. Like any commercial enterprise, the LDCs will have to segment the market and offer differentiated services. In order to retain market share, the LDCs will have to offer a menu of services which meets the reliability, quality and price needs of the segmented and niche markets. This will play havoc with the time-honored notions of establishing rates based upon embedded costs and cost, averaging. In the 1990s, customers will want more options. Some of them will prefer to pick and choose among unbundled services. Other customers will prefer the ease and convenience of bundled services. LDCs must be prepared to give customers what they really want in the form of either bundled or unbundled services. Thus the importance of offering a menu of services. The menu of services must include demand side management options. Already many state commissions and local distribution companies have taken steps to inaugurate demand side management activities. Integrated resource planning will be spurred by the Energy Policy Act of 1992. Customers will look toward their local distribution company as a supplier of energy efficiency and energy conservation services, LDCs must regard integrated resource planning and demand side management as an integral part of their business.

For companies with low-load factors or substantial excess transportation capacity, it will be to the benefit otf LDC consumers, as w«ll as to the LDC, for the local distribution company to aggressively compete to improve the company's load factor and to add levenue-effective new customers. LDCs will be financially healthiar and consumers' rates will be lower to the extent that LDCs are able to maximize throughput and spread common costs to more customers and over more units of usage. For example, in low-load factor circumstances, increasing the usage of natural gas during the summer and shoulder months has the potential to be a win-win for the LDC, new gas users and existing gas users. However, it is essential that such improvements in load factor be in concert with the principles of demand side management and cost-effective integrated resource planning. Improvements in load factor should be based upon efficient use of energy, not inefficient use of energy.

Because end use equipment is so significant in determining consumers' decisions about choices regarding the type of energy used, it may be necessary for local distribution companies to become more involved in the natural gas equipment and appliance market. The involvement will be in three forms: first, more support for research, development, and commercialization of equipment; second, offering financing plans to help overcome the high first- cost problem associated with gas equipment and appliances; and, third, offering technical assistance and equipment maintenance services to industrial, commercial, and residential customers who want such services.

070 A major opportunity for local distribution companies to add value for customers is by delivering a variety of non- traditional, but energy-related services. I believe that many industrial, commercial and residential customers want to have the option of calling upon LDCs for information and technical assistance regarding energy efficiency and conservation, energy services *».rsd gas-fired equipment. They want the LDC to be an available resource for obtaining financing to purchase ga-s-fired equipment and for ongoing maintenance and servicing of such equipment. It will be to the benefit of consumers and local distribution companies if the old barriers to LDCs' provision of related energy services is reduced.

In summary, as never before, local distribution companies will have to pay close attention to their customers. By means of surveys, focus groups, and careful attention to customers' complaints and suggestions, LDCs must be alert to the changes in customers' needs, preferences and expectations. In a quest to know their customers better, LDCs will have to tirelessly ask two basic questions of their customers: How are we doing? What can we do better?

As a result of the increasingly competitive environment, local distribution companies will have to listen and respond to customers far more than in a regulated environment. The key to success will be constant improvement, increasing efficiency, ^nd continuous innovation so as to add value for every customer segment. Local distribution companies which do otherwise will become endangered dinosaurs in the new era.

By now my remarks may have led you to the suspicion that the competitive dynamics of the industry pose inherent conflicts with state regulatory policies which have evolved over many decades. So let me shift my attention from LDCs to state regulation.

One of the great dangers for consumers and industry participants is the possibility of regulatory lag during the 1990s. The regulatory lag of which I am speaking is not rate lag. I am speaking of a more significant regulatory lag, in which regulatory policies fall years behind the realities of the marketplace.

We saw the consequences of such regulatory lag in the 1970s when federal law and regulation artificially suppressed the price of gas at the wellhead, leading to a terrible imbalance between the demand for gas and its availability in the interstate market.

071 In the post-Order 636, post-Energy Policy Act era, it is exceedingly important that state regulatory policies be re-examined and modified to comport with the realities of the 1990s energy marketplace. For example, rate design principles based upon average embedded costs do not fully square with an industry operating in an environment of niche and segmented markets. In segmented market, rates for services will have to accommodate principles of marginal ccst and market value.

Subsidies from one group of customers to another group are often incompatible with competitive markets. Local distribution companies will be operating in an environment of increasing risk warranting higher rates of return. LDCs face market challenges in winning and retaining customers. The gas supply function is becoming mores fraught with risk, as the options for buying, transporting and storing gas increase. More options means more chance of mistake, wore -iidnca of mistake sssns sore chance of regulatory disallowances in prudence reviews. Investors and financial markets will be expecting a greater rate of return as compensation.

Research, development, demonstration and commercializa- tion of end-use technology is costly. If R&O and commercialization efforts are directed toward improving the LDC load factor and thereby helping all customers, a share of the LDC cost of R&D and commercialization should be borne by customers as well as shareholders.

State utility commissions will need to re-examine the nettlesome issue of LDC promotional practices. Promotion of gas sales was strictly barred in the 1970s. In some states, the barrier has been cautiously and narrowly modified. An important issue in the 1990s will be the matter of permitting LDC marketing activities which promote the efficient use of natural gas and improve the load factor and throughput of the LDC to the benefit of existing customers. As a result of Order 636, state utility commissions will need to engage in a thorough examination of prudence review policies and procedures. Over the past decades, the preferred approach of state regulatory agencies has been to engage in detailed post hoc review of LDC purchasing. Such method of prudence review is likely to be both too cumbersome and too unfair to be used after pipeline restructuring.

Other prudence review alternatives need to be examined. One approach is for the utility commission to give prior approval to the LDC's overall strategy for gas acquisition,

07:> 10

transportation, storage and peak shaving and, later, to engage in post hoc review of the reasonableness of the actions undertaken by the LDC to carry out the strategy. Another alternative is to develop a standard or index, based upon publicly available sources of price information, against which the cost of LDC gas at the citygate can be compared. This will avoid the necessity of examination of a multitude of decisions by the LDC with respect to aggregating and shipping gas.

A third approach would be to use measurements of performance pursuant to which an LDC would be rewarded or penalized if the gas acquisition program is particularly successful or flawed. If the LDC's cost of gas falls within a neutral band or zone, as compared to an index or basket of indicators, the LDC would be neither rewarded nor penalized for its gas supply activities. If the LDC's cost of gas is less expensive than the index's neutral zone, the company might be able to keep 50% of the difference as an incentive or reward. If the cost of gas is above the neutral band or zone, the company's shareholders may have to share 50% of the excessive costs.

The ultimate option is for a state to consider the radical step of encouraging competition in the gas supply function downstream from the citygate. Rather than depend upon regulators to engage in prudence review, the competitive market might be relied upon to discipline the LDC gas supply function. Prudence reviews would no longer be necessary to the extent that customers have a meaningful choice of obtaining their gas supply from a source other than the LDC. As strange as this option may sound to American ears, I should point out that the LDC gas supply function is competitive in parts of Canada. Today, to many of us ir. this room, the notion of a competitive gas supply function behind the citygate — for small commercial and residential customers — nay seem like a wild stretch of the imagination But I predict that within several years, many of us will regard that eventuality far more seriously than we do today.

Another set of issues to be wrestled with by state regulators is the degree to which LDC service offerings will be unbundled. As a result of Order 636, the requests, by large commercial and industrial customers, for unbundling of LDCs services will increase. Sooner or later, the compelling logic of LDCs offering a menu of services and providing customers only those services which they truly want will prevail. Over time, unbundling behind the citygate will increase.

In a competitive market, it will be difficult for regulators to maintain either the iron curtain of franchise protection or the iron law of the obligation to serve. In 11

dialogue with all stakeholders, PUCs will need to re-examine the symmetry — in the real world — of franchises and obligations to serve. For example, regulators will need to re-examine the obligation of LDCs to serve customers who have fuel switching capability. Such customers can switch off of ga« whenever a cheaper alternative supply of energy is available. In such circumstance the customer may be getting a free or below-cost insurance policy by relying upon the LDC as an emergency backstop for gas supply. Regulators will need to either modify the LDCs1 obligation to serve these customers or develop a rate design methodology with an appropriate charge for customers utilizing the LDC as the last resort source of energy.

Finally, as the local gas market becomes increasingly competitive, forms of incentive regulation may need to replace the traditional cost-plus regulation. Moreover, the weakest aspect of cost-plus regulation has always been its inability to encourage operating efficiencies or to stimulate entrepreneurial-style responsiveness to customers. Cost-plus regulation permits complacency and does not stimulate rapid introduction of new services or adding value to existing services. Cost-plus regulation does not encourage companies to respond to the particular needs of niche and segmented markets or to continually test the marketplace to determine the types of value-added services which customers want.

Incentive regulation has the potential to bring about increased efficiencies, improvements in services, and a higher degree of customer responsiveness than does traditional regulation. It also has the potential to disentangle commissions from nit-picking cost allocation, cost accounting, rate design and operational issues where the exercise of regulatory judgment is no more wise or perspicacious than results brought about by competitive market dynamics.

In conclusion, the post-Order 636 and post-Energy Policy Act era will be a time of more change, more unknowns, new risks, and new challenges. The paradigm shift from a gas industry shaped by regulation to a gas industry driven by competition will continue. In the 1990s gas market, everything will be dynamic and change will be the norm. Nothing will be static for the industry, for consumers, or for regulators. The successful gas businesses will be those committed to taking advantage of competitive opportunities. The happy consumers will be those who avail themselves of new options. The successful regulators will be those who encourage and facilitate the growth of competitive market dynamics, provide gas companies with the risk and reward incentives to respond to those dynamics, and assure that consumers have

074 12 adequate energy choices and sufficient information to effectively manage their energy needs. In the 1990s we should not try to hold on to the status quo. A failure to change and adapt will be perilous for businesses, harmful for consumers and counterproductive for regulators. Holding to the status quo ultimately proved perilous to the dinosaurs. For us, today, anticipating the need to change, rather than resisting change, will result.in the best outcome. My hope for this conference is that it will help all of us — producers, pipelines, marketers, local distribution companies, consumer advocates, state energy officials and regulators — to understand the new risks and the new opportunities in the post-Order 636 and post-Energy Policy Act era. At the end of the conference I hope each of us will be better equipped to adapt to and succeed in the new era ahead.

075 NARDC-DOB Second National Conference on Natural Gas Use Comments by Michael S. Reeves April 26, 1993 Slide 1. Brief Description of the Markets Mature market - Residential/Coramercial/Industrial 2&3. Importance of Commercial Markets to Companies Growing Customer Base NSG Total 1982-1992 18% 52% 22% 4. Competitive Barriers High Rise & Horizontal/Midrise Operating Costs Favor Gas Even With Rider 255 Electric Heating Rate-Ventilation Fans Use Rider 25 First Cost Disadvantages • 12 KV Riser ($1.00-$1.50 sq. ft. value) Electric Mechanical Systems - Lower Cost 5. District Energy Gas Company Way of Competing With Electric Company McCormick Place Exhibition Authority (MPEA) Was Poised to Go All Electric (In Spite of Gas Operating Cost Advantages) Proposal by Peoples Energy Corp. and Trigen Energy Corp. to MPEA For District Energy Concept Proposal Won Over Self-Generation and Conventional Er.eroy Systems in Competition With Electric Utility District Heating Advantages First Cost Savings, No Operational or Environmental Worries (CFC's); Labor Reduction (O&M Staff) Partnership Contributions Trigen - Experience With Existing Plants Peoples - Local Presence Benefits for Peoples Gas Light Will Sell Transportation Gas Service to the Partnership Eventually Lead to Greater Sales 6. Meeting Challenges New Rate Design Single Block to Declining Block Rates • End Use Rate For NGVs Rate 3 - Demand/Commodity Rate Incentive Programs Air Conditioning Cogjneration Vertical Riser Prime Mover (Just Filed For)

0r« c» Support R&D Programs • Working With GRI Supporting Field Tests NGV Conversion Program Loaned GMC Sierra Truck Trade Allies Building Relationships To Strengthen Infrastructure and Sales Effort Gas Transportation Growth of Transportation PGL - 60% of Commercial Deliveries. NSG - 58% of Commercial Deliveries How and Why it Works For Companies How and Why it Works For Customers Keeps Ga^ Costs Economical Support New Technologies Introduce Customers to New Technology Through Trade Shows, Demonstrations, and Customer Contacts Improve Equipment Efficiencies 7. Future Outlook Identifying Customer Needs Through Market Research - Focus Groups, Surveys & Quantitative Studies Personal Contact Knowing Your Customers • Marketing Information System (MKTIS) - Improved Data Collection System - Should Enhance the Ability to Analyze Markets and Better Serve Customer Needs Promoting Non-Traditional Markets NARUC Support For Gas Air Conditioning From Electric Company DSM Plans Cogeneration For Improved Energy Efficiencies Supporting Natural Gas in the Clean Air Act Amendments Natural Gas Vehicles

077 NARUC-DOE Second National Conference on Natural Gas Use

Michael S. Reeves Executive Vice President Peoples Energy Corporation Chicago, Illinois

New Orleans, Louisiana April 26,1993 The Peoples Gas Light and Coke Company North Shore Gas Company Number of Customers -1992

Residential Residential 793,436 114,814 94% 93% Commercial Commercial 46,903 8,129 6% 7%

-1

Industrial Industrial 4,211 886

Total Customers 844,550 Total Customers 123,829 The Peoples Gas Light and Coke Company North Shore Gas Company I 8 | 1 o si .§> CD (D — ^ t CO >

Ui § CO 3 \ en to £Z an in 00 1 o o s*i O) I o

2 s !_ o o o o o o o o i o s in" Iff CO North Shore Gas Company

Number Commercial Customers of Customers 10,000

8,000

6,000

4,000

2,000

1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 Fiscal Years The Peoples Gas Light and Coke Company North Shore Gas Company Competitve Barriers High Rise - Operating Cost Favors Gas o on * Electric Rate Offset - First Cost Disadvantage * 12 KV Riser Program * Mechanical Systems The Peoples Gas Light and Coke Company District Energy

m Gas Company Way of Competing With Electric Company on • Advantages

• Partnership Contributions

• Benefits for Peoples The Peoples Gas Light and Coke Company North Shore Gas Company Meeting Challenges

• New Rate Design • Incentive Programs o CO • Support R&D Programs • Trade Allies • Gas Transportation • Support New Technologies The Peoples Gas Light and Coke Company North Shore Gas Company Future Outlook

• Identifying Customer Needs

• Knowing Your Customers

• Promoting Non-Traditional Markets

• Supporting Natural Gas in the Clean Air Act Amendments COMMERCIAL GAS COOLING MARKET

by Rich itteilag

Missouri Public Service a division of UtiliCorp United Inc. COMMERCIAL GAS COOLING FACTS

Total installed commercial air conditioning in the U.S. is 116 million tons. Natural gas currently serves 5 percent of this commercial air conditioning market (7 million tons) - 66 percent of the heating market. CO Over 5 million tons of commerciai air conditioning is added or replaced every year. A 500-ton gas absorption cooling unit consumes 12,000 MCF per year in the South and 9,000 MCF year in other regions. ECONOMIC TRADEOFFS Electric Coding Advantages Pjaadvantaflee High efficiency High demand charges Low first cost

CO Gas Cooling Advantages Plaadvantagas Special gae rates Lower efficiency Reduced on peak Higher first cost electric needs

AttemiMid Charges • A Cspitsl Costs + A Operating Costs - Nat Bsnsftt REGIONAL COMPARISON OF SUMMER PEAK CONTItiSUTIOfiS

1982 SUMMER PEAK CONTRIBUTION COMMERCIAL SPACE COOLING 29V* 1 31% RESIDENTIAL SPACE COOLING! 1 11% 16% RESIDENTIAL 2% I Ifltt WATER HEAT 2% 1%

67% 84% OTHER «•%

WEST EAST SOUTH SOUTH NORTH «,— CENTRAL CENTRAL CENTRAL EAST EAST WEST PEAK SHAVING OPERATING STRATEGY Non-RateSwtetf OMMMMI 100 GAS COOLING ELECTRIC 3 80 COOLING 9

J F M A ABSORPTION AND CtNTWPUQAL SYSTEM

10 20 30 40 fO 60 70 80 rau LOAD) CMUlRCOiTS AS A FUNCTION OF CAPACITY TOO

i- •400 ABSORPTION 300

200 CENHttFUQAl. 200 A«m CO 100 250 800 1,000 CWLLEU «ZE (TON) ENERGY EFFICIENCY vs. ENERGY COST

COP Electric 5.00 _ M E 5.26 COP Absorption 0.95 o CO

Avg. Electric Rate _ $21.01/MMBtu- m Avg Gas Rate * $4.97/MMBtu

" $0.0717/kWh Source, Energy User News. SUMMARY OP GA8 SY8TIM PAY8ACK8 COMMMD TO RATI8

Ct»rft>$/kW Bottton 110.80 3.8 2.0 1.0

Chicago $13.24 5.3 2.4 2.0

SanDtego $ 7.31 7.0 2.0 2.0

Atlanta 0 7.47 2.0 4.0 3.7

Phoanlx $ 0.50 4.5 5.2 3.7 CONCLUSIONS

Principal advantaga of gaa eooHng la ttia avoManeo of axpanaiva alaotrlc dtmand charges.

Capital ooat dlffsrtntlal la tha moat Important faetor on CO ths ooat sM» - economies of aeala favor larger systems, cradlt for heating eapaolty la an Important benefit

Hourly running coat comparison la laaa Important to ovarall economics. sen toot ni9t-zo EB-SO-»O OIHO sioa svo

APRIL S, 1993 COMMERCIAL MARKETS 36, 1993 RBKMUCa Of JAKBS A. LEG COL0HDIA OM QX8TRXBUTXO3I COMPMIXEa

I, IMTRQDOCTION.

A. OVERVIEW OF CDC OPERATIONS. B. VALUE OF CDR'S COMMERCIAL MARKETS.

TT. PERC ORDER 636 IMPACTS ON GAS PURCHASING STRATEGIES.

A. LOCs RESPONSIBLE FOR PURCHASING 100% OF SYSTEM CAPACITV AND SUPPLY RBQUXRBHENT8. B. NECESSITY FOR ACCURATE PEAK CAY, SEASONAL AND ANNUAL LOAD FORECASTS. C. HAIHTENACE OP OPERATING INTEGRITY.

III. IMPLICATIONS 07 GAS TRANSPORTATION SERVICE FOR COMMERCIAL CUSTOMERS. A. INCREASING NUMBERS OF COMMERCIAL CUSTOMERS CHOOSING INTEHRDPTIBLB GAS TRANSPORTATION SERVICE. B. ELIGIBILITY REQUIREMENTS. C. DAILY METERING, NOTIFICATION AND MONITOKiNG RJEQOTRBMBWTS. D. GAS SUPPLY PLANNING COMPLICATIONS.

E. AVOIDANCE OF COST SUBSIDIES.

XV. LDC NKRCHANT FUNCTION/OBLinATION TO SERVE. A. TRADITIONAL ROLE OF LDC8. B. NEED TO REDEFINE LDC PUBLIC SERVICE OBLIGATIONS. C. "PARTNERSHIP" PROCESS INVOLVING ALL STAKEHOLDERS.

V. CONCLUSION/RECOMMENDATIONS.

OL OIHO STCO <3t5D ~DOl SENT BYiBIQ BEAR STORES CO, i 4- 2-83 ! 17M2 ! BIG BEAR CONST. •« I120288B22135* I

NJUOTC-DQS HSSTIKO APRIL 36, 1993 ntrsooccnam Big JMT Stoxmm Company, located in OoXxtmbum, Ohio, ±m « Oivi.mi.aa of Thm Pmna Tr*S£io Company hmtdqamrbmrmd in Johnmtatm, Pmaamylvanim. Big Bmar opartf* retail groomxy and dmportwmnt •toraa in Ohio and Wmmt Vlrginl* and aalntalna oftiomm- and varmhouMmt in OoXuabu*.

90QSX fgg»> - X1J GTS Account* mrm located in Ohio and *r* aarvlowd toy Columbl* CM of Ohio.

-jffiip»r»arJk«t« - tfj stoxw* (Total la Off aod HV) "Torty-rour (44 j store* on firaotportafclon (OTS) -X, sir, 307 tb* ffwevimd by ms Jkooountm Zal jfaturai Gaa Coomiaption on OTS - $7,275 Mat ~Dmp*rt»»Bt Star** - IP Storm* -OTS - X3 5ton* -707,aff7 ft* -Annual Coasuaptlon - 7,35a -CoMblnmtlon Starmm - XI 9ton« (Total; 'OTS - S StqvB '664,916 ft* -Annual Conmuaption - 13,457 Met -OfXloa/warahouaa spaoa - $ raellitlmm (Total) 'GTS - 6 Xocstioa* ~l,Z52f9Q9 ft* -Annual CaamuuptioD - 46,343 Hot -Main Bakery - i facility -94,900 *** -Annual Conainptioa - S6,97» Mat -Industrial Accooct - JntarxuptUbJa

097 R-96X 04-02-93 O«:1SPU P002 BIS SENT BYJBIQ BEAR STOREi CO. ; 4- 2-83 ! 17M2 ! BIQ BEAR CONST.•* J1202B8022135I I

SOOPS ftrant,]

-Space flaafc -Hot Waiur -Canarator -P*n K*eh*r "Proof Box -Dahunidification -Dasiceant Dryar* -Stuuar JCoad -i*»* A/C sr -£rigJbar 5tor» ffaaparatura* -ScKmv Humidity -shorter x»jfx»»t rimt "laprovad RafrlgaratiOQ -Jjcwur Xlmatrio SH2*

-CTS Account* -sixty-sight Faoilitia* -Appror. 4.24 Nillioa Sguara Jfiaat -Annual Con»UJar*:iDD - 270.4 JOfof -Haatinsr ^.ad - 59.SI -Cooling Load - 5.6k (Dthiwiditioation) 'Beau Load - 34.5*

!-S6X 04-02-93 04:15PU f003 *I5 SENT BYiBIQ BEAR STORES CO. i 4- 2-83 ; 17M2 \ BIG BEAR CONST." 81202B882213i» 4

HARK3VSR -Natural Gat Supplier -Shipper tor all General Service (QTS) Account* -dominates, Schedules, Balance* on Pipelines -Pricing -B«*«ry - Fixed OMB Priao -General Service Accounts - .Fixed" Margin -Seasonal and Indexed Pricing in Past -City Gate, Vpttraao Plpalina -Replaca* utility as Billing Agwnt -"Pools" Custooars a* sijijlm Aooount Xd n«ar Tax Liability

-Columbia Ona at Ohio p -Bnifarm Raima -Birtorically Sot Alvaya tb» Case -s&mplltlma Bmcomdng QTE custoaor -Proviounly contractuoJ Arz-anpcranta -Reasonable Actainiatratlon Cbargea far QT1 -Umaageary for Lav Suamme Load camtonmx- -Customer "Poola' -AIIOVM Jfarfceter to Coablnm Lav Volume Snd -Working Relationship -Aio«rladgeat>l« Representatives 'Transportation and General Sm^/icm -Billing -Aajumtmanta -Rates -JHev/'Off Accounts -PenaltiB« (Banks) -Curtailnent -Partial Full S«auitaaents -Jtarisnun Dally Volwom -Mnthorlaad Daily Voluaa -Telemetering -Nonitor CornMuaptlon -Additional Custoaar Szpense -Meter -Provide Comaunleationm -should be conmunlaat&d to Custoaar .Explicitly

S-96X 04-02-93 0*:15PM P004 815 SENT BYiBIQ BEAR STORES CO, i 4- 2-93 ; 1'M3 i BIQ BEAR CONST.-* 8120288B2213;# 5

-ColuaMa Gas rran«ni*-*ioa (; -Only Current Shipper1* Agrmmamnt -othmrm in past -CSoluabia Oil/ ~Tmxa& Gam -Marketer Ship* for 073 Accounts -Bio Baax for Larg* Sarvlee (Bakery) -x&rkmter Sah»dulmM and Balances -Faaalfciaw -Brieiny Xato Pipallna -Maintain Shippttr'a Status for Flexibility -Hoort Jntaraction vith £0C and Mazftatar

Money/// -H*p*nd£ on Utility fittea -OTS is Hetrqinal •Largr* or^ is Substantial -RmtJuced Account Payabloe -6T5 From 140+ to 4 Silla Hantbly -General Service Proa 70+ 4 Bill/Mo.

-xeso HonayUl -GCR not Guaranteed Vnan Golny "Off" -Partial Fall Rsguiraaant* -AutftoriraJ«ct to Parcantay* -curtaiiBMt on £DC or Upetraar Pipalina >jDatarainc0 Authorisacf Voluma -Ma«t Pe&k Da^ Xtomand -Must Raly on supplier to Procura Firs Capacity -BaJcary Coaplotaly XntarruptiJbla -fguipaaat Problems switching ruml* -Complying tritb Curtailment -Kaat Jlaclaia -Maintain Iiicfitiny -lover Space Temperature* -ParteAle Heater* -Jfeduc© Outtfide Air, Ariianst -Shift Xn-Store BoJcing to Other Store*

R-96X 04-02-93 04.15PU P005 «15 SSfT BY:BIQ BEAR STORES CO, ; t- 2-B3 i 17M3 I BIG BEAR CONST.« 812O2S892213tf 8

-.ffasiar ho p ^Uniform Mates simplify Eliit cttl Xsponmom -Partial Fall l Paolo 63 & Sffmet chmp, Sescwcm Supplies that, or* Kttaily &tfzl&8t»d Ulttmat* ¥ar&t&k

04-02-93 04:ISPU P006 »15 United Slates Department of Energy/ National Association of Regulatory Utility Conualestonero National Conference on Natural Gas Use New Orleans. 26-28 April. 1993 FUNDAMENTALS OF UTILITY GAS-ACgUXSI- TION STRATEGY FOR THE 1990S (IN 600 WORDS OR LESS) Summary of Remarks by ATIOE Rex Tussing ARTAInc. Seattle WA The reliability of gas supply required by gas-dlstributlon utilities and electric utilities on behalf of their essential-service (core) ratepayers Is reliability at the point of delivery. This kind of reliability is not; for sale jio the filQld.a t any price, but depends on control over firm transmis- sion and storage capacity, and/or over gas flows that can be readily interrupted or diverted, or on the existence of markets that offer assured access at a price to these elements of supply. Such markets firmly entrenched themselves for the natural-gas commodity during the 1980s, and are now emerging rapidly for transmission and storage services. There will seldom be any reason for utilities to pay producers a contractual premium for "firmess" of gas supply at the point of production. An infinitely diverse choice of strategies. In the new open-architecture gas market, there will be an infinitely diverse range of elements from which utilities can choose in assem- bling a gas-supply portfolio. The utilities will henceforth be account- able to the ratepayers and the community through their respective utility commissions for both the strategies chosen and their perfor- mance In terms of gas costs and supply reliability. The basic strategic choice: self-help vs. contracting with an ag- gregator. The most basic strategic choice concerns whether a utility is to (1) aggregate, seasonally shape and firm its own gas-supply portfolio by direct purchases at upstream market centers (mostly in spot transactions), and bundle these supplies March 20. 1993 12:18 PM T ~~^~~~~~~^~~~~~~~~~"""""""""~~ 102 with firm transmission and storage tights held in its own name, or (2) contract out the portfolio aggregation and rebundling functions to other parties (e.g.. producers, pipeline affili- ates, or independent marketers) that offer a firm, sea- sonally shaped supply at the utility's city or plant gate. A tendency can already be seen for the largest utilities to learn toward self-help strategies (No. 1) and for smaller utilities to continue dele- gating procurement responsibilities to others (No. 2). but many excep- tions can be expected to such an alignment. Each utility's strategy choice and the details of its execution will be powerfully influenced, moreover, by the expressed preferences of its utility commission, and especially by the standards and procedures established by the com- mission to monitor gas costs and reliability of service. PUC standards and procedures to monitor supply costs and reliability. The existence of two polar strategic choices, the infinite number of possible variations within each of them and the range of potential combinations of the two. make obsolete the purchased-gas or pur- chased-fue1 adjustment [PGA or PFA) mechanisms-cum-reasonableness reviews used bv most Commissions since the early 1970s. Designing an efficient, fair, and administratively workable substitute will be a challenging task, however, and probably a lengthy one. because of the difficulty of comparing the city-gate costs of supply portfolios con- structed differently for systems having vastly different loads and reli- ability needs.

Market-indexes and cost-sharing incentive systems. The difficulty of comparison will likely push most commissions toward using (spot) market indexes, determined monthly or more frequently, as the basis for gas-cost passthroughs. and toward Incentive mecha- nisms whereby the utility and the ratepayers share any difference (positive or negative) between actual costs and the market index. One result will be to strengthen the tendency cf utilities to adopt self-help supply strategies.

3/20/93 12:18 PM

103 United States Department of Energy/ National Association of Regulatory UUllty Commissioners National Conference on Natural Gas Use New Orleans. 26-28 April. 1993 A Third-Party Summary of ARTA Views on LDC Gas-Procurement and its Regulatory Surveillance The following Is an excerpt from "Consumer-State Regulation: Assuming Greater Role Under Open Access", by William H. Smith Jr.. chief of the Bureau of Rate and Safety Evaluation at the Iowa UUIIU-is Board, in Robert E. WUlett (ed.). The 1993 Natural Gas yearbook C Executive Enterprises Int. Fulfillment of FERC's Order 636 require- without backup reserve service. In the ments will invite consideration of the need ultimate version, no minimum volumes to apply the principles of open end work- would apply, so that residential mar- able competition at the retail level, in June kets would be opened to competitive 1992. the National Regulate*" Research In- service. stitute INRRI) invited such consideration by publishing Occasional Paper «15. State Separate gas cost from distribution Rcgulaton/ Challenges for the Natural Gas cost The cost of merchant service Industry tn the 1990s and Beyond, by David should be a separate element In tariffs B. Hatcher and Axlon R.. Tusslng, NRR1 re- and o;i customer bills. turned to this subject in its September 1992 Review gas purchasing. Gas cost would Quarterly Bulletin with a research paper be reviewed apart from distribution cost entitled "Pipeline Gas Service Comparabil- rate cases. In looking at gas cost dock- ity Rule: What Can State Regulators Do ets. Hatcher and Tusslng's principles Now?" by Daniel J. Duann and David B. suggest that a utility's contract com- Hatcher. (For information on these docu- mlUrents should be no higher than its ments, call NRRI at 614-292-9404.1 captive market base load, and regula- tors should rely on the spot market for These studies bring perspective and contro- requirements above that level. In fact, versy to the las! stage in connecting the these economists would urge regulators completion fostered by the FERC and others to rely on the spot market for all re- to the ultimate consumers of the natural quirements loverstatement of our position gas industry. It lists what the authors view - • A.R.TI because In the worst conditions as the four critlca' elements of the natural the opot market is the only guarantors gas industry today. of reliability. • Commodity sales are competitive and Continue watchtng affiliate transac- need not be regulated. tions for abuse. Especially for distribu- • Most large-volume customers arc non- tion utilities with unregulated supply captive and service to them cannot be affiliates, customers deserve the assur- regulated the same as service to small- ance that, revenues are not being di- volume customers. rected away from the regulated services • Spot markets for gas are effective and or steered toward its. make reliance on supply contracts un- Design a profit motlue for the uttitty necessarily. Historically, gas contracts merchant function, using deviation have not proven enforceable In extreme from spot prices. As merchant service condJUons 11.e .just when they are most becomes a separate enterprise, its cur- needed). rent nonprofit status become unnatural • Restricting resale of transportation and unrealistic. service is harmful. Eliminate resale restrictions from re- The Hatcher/Tusslng paper suggests state tail tariffs. Hatcher and Tusslng believe regulatory agencies consider the following that this approach is the best way to put points. Many of them are already in place rate design to the economic test and in many states. In particular, the last two Cash out Inefficiencies. It was a suc- points would be breakthroughs In state reg- cessful strategy In the deregulation of ulation not yet tested. the toterexehange telephone market. A gas marketer could buy the transporta- • Unbundle gas soles from other service tion necessary to bring a rebundled ser- components. Utilities could continue to vice to the end user. That would effec- offer merchant service, but they would tively bring competition Into monopoly be required to offer transportation with markets and would do so without build- or without sales service and with or ing multiple facilities. United States Department of Energy/ National Association of Regulatory Utility Commissioners} National Conference on Natural Gas Use New Orleans, 26-28 April. 1993 Additional References Statement on Prudence Standards for {Daniel J. Duann and David B. Hatcher} Utility Procurement of Core-Service "Mp-cline Gas Service Comparability Natural-Gas Supply. At an en bane Rule {CTERC Order No. 636): What Should hearing on gas-procurement Issues. Cal- State Regulator! Do Now?", WRRf Quar- ifornia Public Utilities Commission. terly Bulletin. Columbus Ohio: The Na- San Francisco. February 5, 1992. Sup- tional Regulatory Research Institute. plementary Statement, March 9. 1992. September 1992. (D'ivld B. Hatcher and Arlon Rex Tuss- The Gas Indiutxy Invents Itself. A Pro- tng) State Regulatory ChaUeng^ for the legomenon to the Impact of Deregula- Katural-Gas Industry in the 1990s and tion and Unbundling on Gas-Supply Beyond. Columbus OH: National Regu- Pricing. Prepared for the Executive En- latory Research Institute. June 1992. terprises Inc. 13th Annual California Natural Gas Conference. Son Francisco 15-16 March 1993. United States Department of Energy/ National Association of Regulatory Utility Commtsslonssn National Conference on Natural Can Use New Orkana. 26-58 April. 1993 A 1990s Commissioner Views the Role of Long- Term Contracts in Utility Gas Procurement The following is an excerpt from remarks of Daniel WUllam Feuler, President of the Cali- fornia Public U> Itles Commission, before the Executive Enterprises Inc. Thirteenth An- nual California Iwural Gas Conference. San Francisco. March 16. 1993. I believe that Mr. Fessler's view will represent the main stream in gas-acqulsltlon strategy during the mid- 1990s, for gas and electric utilities that I have characterized as large enough to "aggregate, seasonally shape and firm [their] own gas-supply portfollosby direct purchases at upstream market centers and bundle these supplies with firm transmission and storage rights held In [their] own name|s]." — Arlon Rex Tussing

Long-term contracts . . . [avoid] transac- that it reflects specific avoided costs of a tions! costs when contrasted with the al- dimension that render core ratepayers ternative of recontractlng every thirty days neutral on Its lincurrence]. on the spot market. Some of the benefits, • Any "discount" over spot Indexing such as avoided transaction^ costs, work should redound on a pre-established ba- in favor o* both the buyer and seller. Others sis to the utility ratepayers and share- confer an essentially unilateral advantage. holders. I have already spoken of the not inconsid- erable gain to the seller who defines and • Any long-term contract with a pricing cements market share. From the buyer's mechanism which floats so as to reflect perspective, the knowledge that a certain spot prices, or which discounts such an volume of gas is obligated under contract index, may be submitted for and shall relieves a major uncertainty and provides be preapproved upon verification that it price planning stability. If the purchaser is conforms to these policies. a utility, such an arrangement obviates the • Before a utility could divert income to flncurrence) of storage costs which repre- Its shareholders as an earned percent- sent an alternative means of meeting the age of savings over spot Indexing there Commission's insistence that pas supplies would have to be a Commission pro- for the core be secure. ceeding to verify that such savings had. ... I [have] outline[d| a proposed Commis- In fact, been achieved. sion policy on long-term gas procurement. • A proposed contract containing a pre- It took the form of a series of propositions mium over spot could be presented for which, as general policy goals. I (commend- Commission preapproval with the out- ed] to my colleagues. Prominent among come dependent upon proof that cost them were the following: offsets or other benefits would render • Long-term gas contracts have a legiti- the core ratepayers neutral as to its [in- mate place in a utility's procurement currencej. strategy. In reviewing these policy positions I want • The pricing mechanism for such long- to stress that they represent but a stage In term contracts should not seek to "out- my own attempt to grapple with the broader guess" the market but rather should be issues. Of ... benefit In promoting pro- prepared to follow it. curement efficiency In transactions under- taken on behalf of core customers is the ex- • A per se reasonable way to follow the plicit recognition that utility management market is to adopt a pricing mechanism can approach the bargaining table with the which floats so as to reflect spot prices up-side possibility of profits. It is this posi- for natural gas at established market tive Incentive, rather than the belated In- centers. fliction of a disallowance in a traditional • Any utility which forms; a contract in- reasonableness review, that lies at the volving payment of a "premium" over heart of my reform proposals. spot indexing has the burden of proof

106 (SLIDE 1) BALANCING COMPETITION AND REGULATION IN THE 30's

(SLIDE 2}

"Get competitive!" I hear Order 636 speaking directly to me and to

you, telling us all that LDCs are no longer safe monopolies. I know that all

of the regulators out there are wondering how to respond to Order 636. I'm

going to suggest today that the only workable response to the increasing

competition in the marketplace provided by Order 636 is to lighten state

regulation and let the marketplace work.

(SLIDE 3)

Let me give you some background on the company I head - Peoples

Natural Gas. We're headquartered in Omaha, Nebraska.

(SLIDE 4)

Peoples is a part of UtiliCorp United, which includes several gas and electric divisions located in eight states. Peoples is the largest gas division in UtiliCorp. We're regulated in five different states - Iowa, Minnesota,

Kansas, Colorado, and Nebraska.

(SLIDE 5)

We serve about half a million customers. We have almost 200 Bcf a year of throughput, more than half of which is from industrial customers. - Page 2 -

(SLIDE 6}

We're served by nine different pipelines. We face competition in

every one of our market segments - from alternate fuels, bypass, and

municipal condemnation.

Over the years, Peoples has been an active supporter of competition

because we believe it is the best way to ensure a long-term, healthy gas

industry.

(SLIDE 7)

Each of Peoples' states takes a slightly different approach to supply

management review. In Nebraska, we're regulated by city councils, so we

never quite know what to expect from them. Both Kansas and Colorado

have limited review as part of rate cases and PGAs. Minnesota has a

limited audit process which includes an annual filing requirement. Iowa has the most comprehensive process. Since 1985, we've been required by statute in Iowa to make an annual filing that includes a requirements plan and a ten-year forecast of supply and demand. A hearing is held annually for each utility. The Iowa process has largely been used as a communication tool, and it has been an effective forum for an exchange of ideas about the indusii7.

108 - Fage 3 -

(SLIDE 8)

Until the passage of the NGPA in 1978, the natural gas industry was

highly regulated by the federal government. Unfortunately, the regulation

resulted in supply shortages, moratoriums on adding new gas markets, and a general decline in the role that natural gas played in meeting U.S. energy needs. Congress came to understand that low gas prices wouldn't benefit consumers if no gas could be had at those low prices. Deregulation and enhanced competition were introduced at the federal level to correct these problems. fSU 3£ 9)

There really are two forces that work together to protect the consumer and to control LDC behavior - first, the competitive marketplace and, second, regulation. These two forces work in concert and the key is to find the right balance between them. As more competition is injected into the marketplace, regulation must be realized. We have seen that happen at the federal level, as more and more regulation has been removed as the marketplace has become more competitive.

So what does that tell us about state PUC review of supply - Page 4 - management? One response might be to assume that because the FERC is getting out of supply regulation, state commissioners have to step in and fill the gap. I am suggesting to you today that there is no gap to fill with state regulation - competition has already filled that gap.

When you're thinking about what kind of response to make to Order

636, you should be concerned that over-regulating will result in a failure to protect the consumer, just as it did in the 70's.

You should be thinking about regulation which is designed to give

LDCs the freedom they need to respond quickly in the fast-paced environment we're in today.

(SLIDE 10)

When you look at LDC supply management, you should be looking forward, not focusing on the past. Work with us to plan effectively for the future - don't just use your 20-20 hindsight to judge what we've done in the past.

(SLIDE 11)

Whatever you do should be reward-driven. Motivate us to do a better job - don't just punish us for not doing as well as you think we should have. One of the greatest risks LDCs face today is gas cost

110 - Page 5 -

disallowance. With gas costs making up 70% of our total costs and

authorized returns now only around 11%, you can believe this is a risk our

shareholders can't very well afford.

(SLIDE 121

Finally, be sure to recognize the uniqueness of each of the utilities you regulate. We're not alike at all. We have different markets and different supply options. We may have different philosophies about how best to serve our customers. Be careful about comparing us to each other.

No single benchmark is going to work for all the utilities you regulate.

The typical hindsight review process encourages LDC.s to be cautious and conservative. The best decisions aren't always made because the LDC's primary goal is to avoid a cost disallowance. The reluctance that LDCs have had to participate in the futures market may be an example of this. We are motivated to be conservative rather than to be innovative.

With all those thoughts in mind — that supply management review should be forward-looking, should be reward-driven, and should recognize utility uniqueness — I want to make some specific proposals to you today. - Page 6 -

(SLIDE 13)

State regulaators generally were very responsive to Order 436. You

understood that changes were needed, and you gave us tools we needed

to operate in a faster-paced, more competitive environment, including

transportation tariffs, flexible margins, quick response PGAs and cost-

based rates.

(SLIDE 14)

Now I think we al! recognize that more changes are needed in

response to Order 636, but we're not sure what they are. I want to make four specific recommendations to you.

First, most of you are in some stage of looking at energy efficiency planning, or Integrated Resource Plans. An effective Integrated Resource

Plan is something that combines planning on both the market and the supply side. The goal is efficient, effective use of total energy in the state.

Today, an LDC's gas management is something that might get looked at in a number of different forums. For example, in Iowa today, we have an annual purchasing practices [eview, we have rate cases, we have annual PGA filings, and we could have individual dockets. Let's roll all those together and look at LDC purchasing practices just as part of the !RP - Page 7 -

process. That will force us to be long-term, market focused in this process.

So that's my first suggestion — look at your IRP process as the vehicle for reviewing supply management.

(SLIDE 15)

Second, let's start to look at market-based pricing again.

Traditionally, we relied on market-based pricing. Suddenly, in the '80s, however, we discovered that industrial customers would no longer pay what we were charging and we started to move to cost-based pricing. I think what really happened there is that we failed to adjust our prices in response to the market until we found customers refused to use our product or bypassed us.

It's time to start to think again about market-based pricing, and how we can get this to work over the long term. This may mean flexible margins, elimination of PGAs, and sven total deregulation in some markets.

A focus on market-based pricing will allow us to acknowledge and respond to the competitive forces that now exist in the marketplace.

(SLIDE 16)

Third, let's start to look at some incentive regulation. I assure you that monetary rewards are the best way to get us to do something you want ~ Page 8 -

us to do. Let's try some pilot incentive regulation programs to see how they work. These programs should be the best way to encourage utilities to improve service and lower costs.

{SLIDE 17)

Finally, with the enhanced competition we are experiencing in the marketplace, it's time to look at relaxing the utility's obligation to serve. We need mutual obligations between ourselves and our customers. We can't be placed in the position of being forced to be the supplier of last resort if we are not being adequately compensated for it. It's not fair to our loyal firm sales customers for transportation, bypass, and alternate fuel customers to be able to jump off and on the system at will.

{SLIDE 18)

Just to summarize my remarks today, I'm asking you to remember that regulation must balance with competition and that you should be looking for solutions that reward, not punish your utilities.

{SLIDE 19)

I've made suggestions for four ideas you should take home with you:

IRPs should be your primary vehicle for reviewing LDC supply

management, and you should be looking at market-based

134 - Page 9 -

pricing, incentive regulation and relaxing the obligation to

serve.

(SLIDE 20)

As I look out into the future, I see a gas industry that progresses to deregulation as many other industries have progressed. I see all customers, including residential customers, having choices. And, finally, I see regulation focused mainly on safety issues rather than rate and service regulation, because our customers themselves will be regulating our behavior.

Order 636 is a signal to us that more needs to be done now to allow competitive forces to reach the marketplace. Let's continue to stretch ourselves to remove regulatory barriers which encourage LDCs to act like old-fashioned monopolies.

115 FROHMD PEOPLE'S COUNSEL TO!91282S9BH213 flPR 9. 1933 UsB6f*1 P.BB

PRESENTATION OUTLINB DOE/NARUC NATIONAL CONFERENCE ON NATURAL QAS USB

State Regulation and Market Dynamics in the Post 636fEntrgy FoHey Ad En

Puul S. Bui&lay Deputy People's Couneel

of LDC Gat Acquisition and Planning Decisions

I. Overview:

'Contest of Review - Retrospective v. Pj©-»ppioval

»Mtiyities_Re_ylewefl " Traditional review of gas acquisition, but review is extended to include involvement at FERC in 636/Pipoline settlement development.

II. Onder No. 636 Tiovrfopment/Spcrifics

IQ. Integrated Resource Planning Technique!

•Array of choices for meeting anticipated load (Including promotion of DSM) requires the application of more sophisticated modeling techniques and econometric models • - Electric end Gas review has roore similarities than ever.

UD PEOPLE'S COUNSEL 04-09-93 10:07AM POOS »4 2 "PUC REVIEW OF SUPPLY MANAGEMENT"

Stephen A. Furbacher April 26, 1993 NARUC/DOE Conference

Thank you, for the introduction. I believe that the value of this panel is the discussion, so I promise to be brief.

It's an exciting time to be discussing this topic - a time of significant transition for our Industry with FERC Order 636 changing the way business will be conducted and spreading the risk across all segments of the value delivery chain. And, that includes the end use markets. At the same time, FERC Order 636 is creating significant opportunity for all of us from producer to end use markets. Many of us are changing the role we must play. It can be a positive and rewarding experience or it can be traumatic - we will each have to make the choice as to which it will be. Finally, this topic is extremely important to us because it's vitally important to our customers -- the millions of natural gas users that we represent across the country.

Today, I'm going to suggest a framework for LDC's and PUC's to use in making decisions about natural gas supply. This framework is based on our own experience in doing the snme thing for our Corporate facilities. I'll provide a bit of information about Chevron to set the context for the framework, but I promise to keep the propaganda to a minimum.

Chevron is a large, integrated, international energy company with interests in oil and natural gas exploration, production, marketing, refining; and, also in chemicals and coal. To illustrate our size, we are both one of the largest refiners of crude oil and one of the largest producers of natural gas in the domestic U. S. Our natural gas efforts are extensive. We have supplies in most major domestic producing basins and we market in all major markets in the country. We market natural gas in the U.S. for our Canadian affiliate. And, Chevron is a major consumer of natural gas. This slide shows our major facilities in the domestic U.S. -- primarily refineries and chemical plants. Together they consume more than 650 MMSCF/Day. Our Natural Gas Business Unit is responsible for the natural gas supply to all of them; a role that is essentially the same as that played by the LDC for their customers. These combined activities give us a unique perspective on the topic of our panel today.

Ultimately, I'll describe a producer's view of the PUC role in today's natural gas business. However, I cannot do that without first talking about the challenges and opportunities that face an LDC today, as the two are inextricably linked. By way of illustration, I will share our experience as a major supplier of natural gas to our domestic Corporate facilities - things we've learned by trial and error. Through this analogy, I hope to provide some insights that will allow you to avoid the same path we took to get where we are today. I'll then finish with some thoughts about the implications I set for the PUC in the post 636 environment.

The process we use starts with our customer - it wasn't always this way. We all assume that we know what our customers want and need, only to be surprised by their negative reaction when that's what we deliver. We start by working closely with the refinery management to fully understand their operating characteristics, capabiiities and limitations, and, most important their economics. Then, together, we develop a clear agreement as to their risk tolerance .... that means understanding their safety concerns, cost structure, and the impact of things like supply disruptions and curtailments on theii operation. When finished with these steps, we have together built a supply strategy that supports their operating objectives within an agreed on level of risk, and, we established the basis for performance review and oversight. Finally, we complete our work with strategy implementation, measuring performance and adjusting the strategy as required to meet established objectives.

I will use a refinery example today, but could just as well be any of our facilities. This slide illustrates some of the key areas of focus for one of our refineries.

1) Supply security - there are two areas of focus. A refinery has processing units that cannot be shutdown without significant economic or safety implications. For example, boilers ami crude distillation units require a bnse load, uninterruptible supply of natural gas. They also have a number of units that do not have the same need for .;upply reliability and can be supplied with interniptiblc gas.

2) Swing supply - there arc two areas of flexibility. They must have the ability to make significant changes in natural gas demand as process units are shutdown for maintenance, some for extended periods. They, also, must have the short term flexibility to increase or decrease gas supply minute to minute and day to day to meet changing operating conditions in the refinery.

Peak load - like an LDC they need the ability to call on significant increases in gas supply to meet extraordinary operating conditions.

3) Price - they also need to minimize the total cost of their natural gas supply as it is a significant percentage of their costs.

As you can see, a refinery's natural gas supply requirements are very similar to those of the customers behind an LDC. The uses are different b'it the type of services they need are sirr.i'ar.

Next the Natural Gas Business Unit, like an LDC, goes to work to arrange the natural gas supply for the refinery. First, we set aboui crafting a supply portfolio to meet the unique requirements of that particular refinery. The supply strategy developed jointly with the refinery is the key to this effort. We cannot predict the future so we must build the supply portfolio to anticipate a variety of possible futures we can see. We often make the mistake of believing that the future will always look much like things do today - we extrapolate today's conditions out into the future. This is especially easy to do when things are going our way. We can start to believe we're invincible. Then, things change - that's why we always use a supply portfolio that considers a variety of scenarios for the future.

We determine the mix of equity and purchased natural gas we'll use and arrange for transportation, both firm and interruptible. We also acquire storage, if that's required. Finally, we build price, term, other services and risk management into the portfolio. We look at the overall value being delivered for a particular price, compare it to the competitive market for equivalent value. We analyze the reliability of the various suppliers and supply options. We consider how much price volatility we can tolerate and act accordingly to manage that risk; futures contracts, fixed price contracts, options and swaps are some examples.

When this work is finished, we have developed a natural gas supply portfolio that meets the broad range of needs our customers have identified - both for short term operation (much easier to predict) and longer term supply and price security. And, we have metrics for performance evaluation and signposts to indicate that conditions are changing and that we need to make adjustments.

In OLT business, the oversight roie is played by the refinery management. Like the PUC, theirs has also been a hindsight review process in the past. We'd put a strategy in place and wait for the. inevitable criticism and 20-20 hindsight review as the future unfolded. Sometimes, we'd be right and sometimes we'd be the bad guys. It certainly led to very short term oriented and cautious behavior on the part of our gas supply people. Since our recent decision to get them directly involved in developing the sirategy and determining the review criteria, it has become a true partnership with all of us taking ownership of meeting the customer's needs.

To judge performance prospectivcly, we ask ourselves: Did the portfolio make sense when it was developed? Are the contracts consistent with the strategy we put in place? We use hindsight review to make adjustments for the future - not to force retroactive changes to commitments and terms of compensation.

Let's shift away from my example and talk about implications for an LDC. The process must also start with the customer. You must use real data and not perceptions and past practice. The customer issues are very similar to those I've described: supply security, volume flexibility, cost and risk tolerance. But, the importance of each varies from customer to customer. The supply management considerations are very similar. Among the considerations to understand are: supply sources; supplier capabilities and their ability to meet commitments now and in the future; the risks associated with various options; transportation and capacity release storage; and, the financial markets are examples. Also, you must consider the important portfolio components, such as supply diversity; Gwning storage or contracting with others for take flexibility; owning firm and using interruptible transportation versus letting others deliver for you; best cost versus least cost; and, managing risk yourself versus letting others provide the service.

The issues are many and are complex, making it very difficult for an LDC in an uncertain regulatory environment. This leads us to the PUC parallel.

I'm not going f. dwell much on the historical practice of hind sight prudence review except to s-.y that I do not see a place for it, as we've known it in the post 636 environment, without exposing the LDC and, more important, the end use customers to high risk and a very uncertain and rocky future.

I'll say it once again, "We cannot predict the future." Given that, I suggest we must work toward a relationship between LDC and PUC that is forward-looking and focused on the customer. They must work as partners to agree on acceptable risk tolerance and the basis and purpose of performance measurement. Establishing a degree of consistency that is based on sound business and economic practices is critical. Next they must shift from least cost to best cost analysis. They must consider cost in the context of an overall supply portfolio and supply strategy — including natural gas supply, transportation, storage and the range of uncertainty about the future. The PUC must create an environment that encourages and gives their LDC's incentive to take advantage of the new opportunities in Order 636.

Since I've referenced it several times today, I'd like to share my views on FERC Order 636. First, I believe that it increases the variety of options available to those looking for natural gas supply. And, I agree that LDC's will share more of the risk in the value delivery chain than they have historically.

Having said that, I want to emphasize that I see these as potentially very positive for the LDC and (heir customers. I believe they have the potential to actually reduce risk for those who actively seek the opportunities it affords. "How is that?" you're probably asking.

No longer will they have to settle for "the average." The LDC and PUC have the opportunity to craft the supply portfolio that meets their specific needs. And, they will have to pay only for the value in that portfolio without subsidizing services they don't need or use. With the wide range of services being offered today, the LDC and the PUC can achieve whatever level of supply and price risk they deem appropriate for their unique situation.

The key will be to shift from buyers to rational shoppers. The rewards will go to those LDC's who aggressively make this shift. They will, then, have to master complexities of purchasing, optimize their supply portfolio, manage storage efficiently, deal effectively with transportation and capacity release and utilize the available risk management tools.

In closing, I'm sure you're tempted to say, "That's easy for you to say since you're in the business." My response is that you're in the business too. We've learned to do this stuff the same way anyone else will - by doing it. I assure you it's not rocket science or we wouldn't have come this far so rapidly. Remember, it all starts and ends with a strong focus on and connection to our customers.

Rest assured, help is available. Look to others in the business to share their experience. And, I'll commit to being available to work with you, if you want. Finally, the choice is yours. The winners wiil be those who step up and aggressively take advantage of the opportunities.

Thank you again for this chance to share my views with you.

4 APRIL 1993 OVERSIGHT OF REGULATED UTILITIES' FUEL SUPPLY CONTRACTS: ACHIEVING MAXIMUM BENEFIT FROM COMPETITIVE NATURAL GAS AND EMISSION ALLOWANCE MARKETS

By Adam B. Jaffe and Joseph P. Kalt Executive Summary

An ongoing trend toward deregulation and undermine the important national experiment with reliance on competitive markets is challenging and the use of omissions trading to minimize the cost of changing the traditional rotes of the Public Utility air pollution control. Commissions (PUCs) that regulate the nation's local gas and electric utilities. When regulated The simplistic view that all commodity utilities under PUCs' jurisdiction purchase major acquisition transactions should be evaluated inputs in newly created, or at least newly freed, relative to the spot price ignores the importance of markets, how can regulators ensure that the risk management. In industries in which utilities do so in a way that is in the best interests investments must be made in capital assets with of the ratepayers? It has been argued by some that long useful lives, risk is a real social cost that can be the existence or potential existence of public "spot" managed but not eliminated. Risk raises the cost of saarkets for commodities such as natural gas and capital and discourages productive investment. An pollution emission "allowances" offers an easy important source of risk associated with these solution to this problem: simply require utilities to investments is price volatility. Efficient purchase these commodities in the spot market, or, management of risk, including risk due to price alternatively, permit them to purchase as they volatility, is one of the functions that competitive choose but allow them to recover in rates only the markets perform well. In a highly evolved current spot price. commodity market, there will exist a diversity of contractual forms and options, which permit the Proposals of this type are based on a fundamental risk of price volatility to be transferred to those misunderstanding of how competitive markets parties who can bear the risk most efficiently. This operate, and of the potential they hold for diversity of contractual forms is absolutely improving the performance of the gas and electric necessary for market participants to be able to hold industries. The implementation of such "spot only" portfolios of supply options that yield a better standards with respect to gas purchase decisions by combination of risks and prices than can bo LDCs and electric utilities, as well as utility trades achieved through sole reliance on spot pricing. governing emission allowances under the 1990 Clean Air Act Amendments, will stunt the healthy Unregulated, competitive firms development of gas and emission allowance that make iong-lived __ markets, raise costs to ratepayers, discourage the investment. ECONOMICS expansion of the nation's use of natural gas, and that require RESOURCE GROUP

C 121 a continuous, reliable supply of inputs do not rely financing from a debt/equity ratio of 75/25 to a exclusively on spot markets for the supply of those ratio of 25/75 would raise the costs of new gas-fired inputs. Such firms typically utilize some electric generation units by more than 16%. If combination of vertical integration, long-term PUC policies impede the development of an contracts with some degree of price fixity, and price efficient emission allowance market and thereby hedging, along with spot-market input purchases, block a shift toward natural gas as an anti-pollution 1 to meet their needs. There is no valid economic or strategy , each foregone mcf of gas use will cost the nation on the order of $0.16-$0.45 — with public policy reason for preventing regulated firms aggregate stakes in the hundreds of millions of from adopting this sort of portfolio strategy. dollars. Indeed, public policy should create incentives and mechanisms that actively encourage and facilitate The design of efficient policies tor regulatory the development of acquisition strategies that oversight of LDC and electric utility decision involve diverse portfolios. making is inherently difficult. The essence of the problem lies in the unavoidable need to make The smkes in this debate are large. Because the decisions in an ex awe environment of uncertainty, cost ot financing cnpiuil investments is adversely while revelation of the payoffs to decisions can affected by increitses in risk, PUC policies that only be known e.v pou. In such u context, public mcren.se risk by stifling the development ol the policy musr be particularly concerned with the needed diversity of contractual forms will raise incennves that it presents to economic agents, and costs throughout the affected industries. Increases with maximizing the opportunity for the forces of in producers' capital costs will lessen the supply of competition to operate. Absolutely guaranteeing gas and thereby raise its price. Increases in gas and "right" decisions and no mistakes is impossible. electric utility risks will further raise costs to Standards and procedures that use competition and ratepayers. Increases in risks associated with the use economic incentives provide PUCs with the most of emission allowance markets and natural gas will viable approach to ensuring the prudence of gas, bias pollution compliance decisions in favor of electricity, and allowance market participants' capital intensive solutions such as scrubbers, raising decisions. the cost of pollution control and undermining the success of the emissions trading system itself. What are the elements of an approach to state regulatory oversight of the performance of LDCs This study finds that, to the extent that "spot and electric utilities that will rely on competition only" PUC oversight policies choke off efficient and appropriate incentives? At least three risk-reducing and risk-shedding contractual principles stand out. opportunities in the natural gas and emission allowance markets, the debt-carrying capacities of 1. Unbundling and Deregulation: Where affected firms are reduced. This causes a shift markets are workably competitive, competition toward more expensive equity forms of financing. rather than regulation should be utilized to govern In the case of gas supply investments, the capital ex ante and ex post performance. costs of gas development and delivery can be raised as a result by as much as $0.80 per thousand cubic As a working presumption, this means that many feet (mcf). Gas-using electric companies can be of the functions that have traditionally been similarly affected. We find that each 5% reduction bundled with the physical delivery service provided in the debt share of new units' financing by local distribution companies may be more corresponds to a 1.6% increase in the revenues efficiently provided under state-level policies of needed to cover the units' costs; and pushing the unbundling and deregulation that parallel those

122 that have been implemented at the federal level. In fact, the value of portfolio strategies is widely Unbundled open access to transportation on local recognized by market participants and their systems could be expected to result in the regulators. As applied to acquisition and pollution proliferation of market competitors that we have abatement, such strategies would be natural seen operating on interstate pipelines. Brokers, extensions of the portfolio-based Integrated marketers, producers, risk intermediaries, supply Resource Planning (IRP) systems that are now aggregators, storage arrangers, and so on are all widely used in determining utilities' capital potential competitors for the business of local gas investment portfolios. customers. This is perhaps most evident in the case of large industrial gas users, who have already been A key component of an effective portfolio clamoring tor bypass of, or open access on, local approach to PUC oversight of utitities' natural gas distribution systems. Even in the case of smaller and emission allowance contracting is pre-approval industrial, commercial, and residential customers, of the composition of acquisition portfolios. Pre- so-called "core aggregators" could be expected to approval policies would require a gas- or allowance compete for sales traditionally made by LDCs. In purchasing utility to justify the composition of its tact, available evidence indicates that consumer acquisition portfolio before the PUC, much the prices are lower under such conditions rhnn they same way that 1RP policies now require utilities to would be under traditional LDC rare setting. justify the extent of their reliance on Demand-Side Management (DSM), base-load capacity (either In the long run, fostering the emergence of a utility-owned or purchased), peaking capacity, competitive retai! gas merchant industry offers short-term purchase commitments, and so forth. PUCs the potential to allow the competitive An effective pre-approval process would thereby market to take over the burden of monitoring the establish parameters on the relative shares of prudence of utility supply decisions. In the short purchases of different types, e.g., spot purchases, run, even the development of limited competition contracts with prices indexed to the spot market, would greatly facilitate regulation of the merchant fixed price contracts of various durations, and function, because the prices charged by hybrid contracts such as variable-price with a floor competitive entrants would provide the best and ceiling. Pre-approvat of portfolio structures possible yardstick against which to compare utility can enhance the sustainability of the regulatory prices. bargain by publicly and procedurally committing the PUC. In this way utilities could acquire the 2. Pre-Approval of Contract Portfolio inputs they need with commitments designed to Structure ia the Context of Integrated minimize price risk, and could do so without Resource Planning: To the extent that PUCs unduly exacerbating regulatory risk. perceive that LDCs and electric utilities continue to have market power in their gas and electricity 3. Use of Competition and Incentives to sales functions, pre-approval should be given to Minimize the Cost of Portfolio Components: broadly outlined portfolio strategies for gas (and, as Competitive bidding requirements within pre- the market develops, emission allowance) approved portfolio categories of gas and allowance procurement. acquisition terms should be used to promote utility performance. By pursuing a portfolio of contractual terms in its gas acquisitions, for example, a utility can take A PUC that has established appropriate advantage of market opportunities in many parameters for the composition of a utility's different form- jf transactions as they arise, while acquisition portfolio should also be concerned diversifying it' aix of price and supply reliability. about the utility's efforts to acquire the individual

123 portfolio components at least cost (with actions of regulated firms in these markets will appropriate consideration for non-contract stifle their development and thereby reduce the circumstances, such as the creditworthiness of the social benefits that are potentially available from seller). The simplest mechanism for achieving cost deregulation and the use of market-based efficiency, and the one that fits most directly into approaches to environmental protection. evolving 1RP frameworks, is to rely on competitive bidding for supply of the different portfolio Regulatory reform and the evolution of new components. That is, once the quantities that are policy inevitably move with a "two steps forward, to be secured in various contracting categories have one step back" pattern. The unwinding of the old been determined, utilities would seek bids for system of regulated fixed-price contracts governing supplies meeting the parameters specified tor that fuel acquisition in favor of markets, and the category. Parameters specified would include development of an active and visible spot market contract attributes such as term and reliability, and for gas, are extremely important and have also seller qualifications such as minimum assets benefitted consumers greatly. We are now on the and other financial indications necessary to ensure threshold of the next major step forward, in which contract performance. Utilities chousing to the structure of these gas markets will widen and acquire gas or make allowance purchases (or sales) deepen, again to the benefit of the ultimate would be obligated to select the supply options that consumer. The same potential for gain exists in offer the best combination of price, non-price environmental policy. The innovative regulatory terms, and non-contract conditions. PUCs could regime created by the 1990 Clean Air Act appropriately monitor the competitiveness of this Amendments offers the potential to achieve process, and are generally familiar with doing so. significant pollution reductions at a cost far less than would be possible with traditional regulatory It is important to emphasize that the regulatory tools. It would be unfortunate indeed if these burden of portfolio pre-approval and monitoring of market processes in gas procurement and emission least-cost bidding are only necessary to rhe extent allowances were stifled in their infancy because of that unbundling and direct competition for retail inadequate understanding of what competitive customers are not implemented. In effect, portfolio markets are all about. pre-approval and lease-cost bidding requirements are imperfect methods for replicating the price discipline that competition would otherwise create. The imprecision and cumbersome nature o( these Professor )affe is Associate Professor o) Economics, Department of Economics. Harvard University. Professor Kak procedures are strong arguments in favor of the is the Ford Foundation Professor of International Political transition to competition as the solution to the Economy and Academic Dean for Research, John F. Kennedy problem or ensuring that acquisition behavior is School of Government, Harvard University. Both are also Senior Economists with the Economics Resource Group, efficient. Cambridge, Massachusetts. This research was funded by Enron Gas Services Corp. The views contained herein are The new era of relying on competitive markets solely those of the authors. to achieve public policy objectives with respect to public utilities and environmental protection makes the jobs of PUCs much harder. To get the maximum social benefit from these policy innovations, regulated firms must be given incentives to participate in these complicated, evolving markets. There is a grave danger that the adoption of simplistic rules for evaluating the 124 GOVERNMENT NATURAL GAS VEHICLE INITIATIVES: PAVING THE WAY

Jamas S. Cannon Energy Policy Analyst New Mexico Energy, Minerals and Natural Resources Department Santa Fe, New Mexico USA 87501

NARUC/OOE National Conference on Natural Gas Use New Orleans, Louisiana April 26-28, 1993

Abstract

Driven by environmental and energy security concerns, the U.S.A. has embarked on a major program to replace petroleum fuels in the transportation sector with cleaner-burning alternatives such as natural gas. Since 1989, about 30 of the 50 state governments have onacted programs to promote or require use of alternative transportation fuels. At the federal government level, provisions of the 1990 Clean Air Act Amendments and the 1992 National Energy Policy Act establish broad alternative transportation fuel use initiatives, Including a clean-fuel use mandate applicable in 150 cities. The Clinton Administration has repeatedly advocated increased use of natural gas vehicle technology. The Department of Energy has drafted a Presidential Executive Order which requires the federal government to purchase at least 20,000 alternate-fueled vehicles beginning in 1994 for use throughout the country.

State and federal government programs already in place in the U.S.A. will create a market for more than 1.0 million alternative fuel vehicles this decade. Many, if not most, of these vehicles will be powered by natural gas. This paper will discuss four types of state and federal government programs which are currently in widespread use to require or encourage use of alternative transportation fuels. These policy arenas are:

/ Vehicle conversion mandates. / Financial incentives. / Regulation of alternate fueled vehicles, including rate-setting policies of state utility commissions. / Task forces and committee studies.

The attached table provides a matrix of state government activities in these four areas. The matrix will be discussed during the presentation.

125 Revised March 10, 1993/Page 1 State Government initiatives tc Promote Natural Gas Vehicles Prepared by the New Mexico Energy, Minerals and Natural Resource; Department

State Vehicle Conversion Mandates Financial Incentives ReguJation of Alternative Fueled Task Forces/ Vehicles Committees/Studies Arizona HB 2433 (1991) mandates that Und8r HB 2433 alternative In 1989 the Department of the state must purchase fueled vehicles pay a reduced Transportation completed a 2- alternative {fueled vehicles when annual vehicle license fee. Also, year demonstration of production line models are the road tax for natural gas tax alternative fueled vehicles. The available and life-cycle costs are is only 5.01 /equivalent gallon, 1991 State Energy Policy calls withir. o% of current costs. compared to 0.18/gallon for for a long-term plan to convert gasoline. government vehicles.

Arkansas In 1991, a 9-member alternative fuels commission was established to coordinate alternative fuels market.

California SB 1123 (1989) requires 25% of SB 2600 (1990) provides a tax In 1390 the Air Resources AB 1338 (1992) authorizes the all newly acquired state vehic'es credit of $1,000 per auto and Board adopted a four-tier California Energy Commission to to have Jean-fuel capability. 03,500 on other vehicles for structure of increasingly strict develop and submit cost of devices installed on new tailpipe emissions standards for recommendations to the SB 135 (199 V, requires all or used vehicles to convert them tight and medium duty vehicles. Legislature for conversion of > - passenger vehicles for hire in non- to Low Emission Vehicles. Compliance with these state universities' shuttle-bus attaintment areas to usa standards is expected to system to alternative fuel. alternative fuels. SB 1006 (1989) exempts the encoursga alternative fuel use incremental cost of any "lean- over the next decade. The national Clean Air Act (1990) fuel vehicle from the state sales SB 547 (1991) provides that requires that a minimum of tax. ownership or operation of a 150,00 clean fuel vehicles ba sold facility selling retail natural gas in California annually from 1996 Natural gas and LPG cars pay an to public for motor fuel use nol through 1998. The annual sales annual flat fee of $36.00 in lieu to be construed as a public then jump to 300,000 vehicles. of per gallon road taxes. utility.

AB 1607 (19S1) allows utilities to build and recover costs from NGV compression stations, and NGV conversion or maintenance facilities Revised March 10, 1993/Page 2

St&te Vehicle Conversion Mandates Financial Incentives Regulation of Alternative Fueled Task Forces/ Vehic!e3 Committees/Studies Colorado A 1990 law (HB 1275) requires In 1989, legislation was enacted A 1930 law removes the sale HB 1275 (1990) established an 10% of new vehicles purchased that provides $200 rebate for of nature! gas as a Alternative Fuels Advisory or leased by state agencies during any person who acquires a clean transportation fuel from the Council to develop a state fleet FY 91-92 use clean fuels. The fuel vehicle or wtio retrofits an jurisdiction of ths Public alternative fuels plan. percentage rises to 40% by FY existing vehicle. HB 1305 Utilities Commission. 94-95. 11992) expanded the rebate to $1,000 per vehicle. The Denver City Council enacted an ordinance in 1990 requiring all H6 1191 (1992) provides a tax fleets of 30 or more vehicles to rebate of 5% of the purchase convert 10% of their vehicles to cost of an alternate fuel vehicle. clean fuels by Dacember 31, 1992. Natural gas is exempt from $. IB/gallon road tax, but NGV owners must pay a flat annual fee between $75 and $125. Connecticut Act 91-178 (19911 establishes a 10% tax credit for any investments or expenditures relating to alternative fuel vehicles until 1993. The Act also exempts from sales tax and o * use tax alternative fueled -I vehicles and equipment used in compressed natural gas fifing stations.

District of A 1990 law requires owners of Columbia government and private fleets of 10 or more vehicles to convert 5% of their vehicles to operate on clean alternative fuels annually beginning in 1993 through 2000. Starting January 1, 1998, only commercial vehicles operating on clean alternative fuels can operate in the Centra! Employment Area between sunrise and sunset from May 1 to September 15. Revised March 10, 1993/Page 3

Stats Vehicle Conversion Mandates financial Incentives Resulatfen of Alternative Fueled Task Forces/ Vehicles Commiuecs/Studies Florida Governor's Executive Order 91- 253 M9S1) mandates alterative fuel use in state agency vehicles. State agencies must submit budget amendments to begin use of alternative fuels in air quality non-attainment areas. By 2000, all possible fleet vehicles wii! be required to use most efficient, least- polluting alternative fuels.

Georgia A 1992 law exempts retail sals of natural gas as a transportation from tha jurisdiction of the Public Service Commission. Hawaii A 1991 law requests state agencies to study and defr/ie alternative motor vehida fuels, the economics of alternative 1 • fuel use and the short-term and long-term benefits of using or alternative fuels.

Iowa SF501 (19911 requires a Alternative fuel vehicles may be Iowa Agriculture and Land minimum of 5% of new state financed under Iowa Energy Stewardship Dept. has drafted a vehicles must be Alternative Bank Program which provides bill to create office of fueled beginning in 1992, financing for state/local Alternative Fuels Coordinator. increasing to 10% in 1994. agencies, school districts.

The road tax for natural gas is $.16/gaflcn compared to 3.20/gaflon for gasoline.

Kansas Executiva Order 92-152 directs all state agtndes to us* alternative fuels when it is cost affective to do so. Revised March 10, 1993/Page 4

Stars Vehicle Conversion Mandates Financial Incentives Regulation of Alternative Fueled Task Forces/ Vehicles Committees/Studios Kentucky A T 992 law removes tho sale of natural gas as a transportation fuel from the jurisdiction of the Public Utilities Commission.

Louisiana Act 927 (1990) requires 30% of Act 1060 (1991) provides a A 1930 law removes the sale new state government fleet 20% income tax credit for of natural gas as a vehicles to be capable of burning alternative fueled vehicles and transportation fuel from the alternative fuels by September refueling equipment. ji Ttstiiction of thg Public 1994. Percentage increases to Utilities Commission. 50% in 1996. Percentage could go to 80% in 1998. pending a review.

Act 954 (1990) axtends the mandate to all political subdivisions. Massachu- Road taxes for natural gas and setts ' 'G are about S.IO/gallon compared to $.21/gallon for gasoline. Maryland A 1992 law removes the sale Maryland NGV Working Group of natural gas as a to submit recommendations to transportation fuel from the the legislature on natural gas jurisdiction of the Public vehicles. Utilities Commission.

Minnesota Natural gas and LPG vehicles pay A 1984 iaw removes the sale an annual fiat tax in lieu of a per of natural gas as a gallon road tax. transportation fuel from the jurisdiction of the Public Utilities Commission. Revised March 10, 1993/Page 5

Slate Vshicle Conversion Mandates Financial Incentives RBjjutet'cDrt of Alternative Fueled Task Forces/ Vehicles Committees/Studios Missouri A 1991 law set a conversion timetable for government fleets of 15 or more vehicles. New vehicles must oe capable of burning alternative fue's according to the following .schedule: 10% by July 1996, 30% by 'ly 1998, and 50% by Jujy 20u0. By July 2000. 30% of all vehicles must operate soloiy on alternative fuels. Nevada Tho roed tax for LPG and natura! AB 812 11991) directs the State gas is about 5.18/gslJon Environmental Commission to compared to 9.22/gailon for develop regulations for tha gasoline. conversion to alternative fuels of state vehicles in cities with a population greater than 100,000. Additionally the i • Commission must complete two alternative fuels studies by the end of 1993.

New Mexico HB 404 (1992) requires that 30% HB 404 (1992) establishes a $5 HB 404 exempts sale-for-resale In 1991 the Clean Alternative of new state government vehicles million loan program for of natural gas from Public Fuels Task Force presented to purchased after July 1, 1993, run alternative fuel vehicles. No Service Commission jurisdiction legislature recommendations for on alternative fuels. The money has been appropriated to and authorizes incentive a state alternative fuel vehicle percentage increases to 60% in date to fund this program. programs for natural gas conversion program. mid-1994 and to 100% in mid- vehicles. 1995. Natural gas a;.a propane vehicles pay an annual fee of $75 in lieu of a per gallons road tax. Some government vehicles are axempt from this fee.

New York S 7424 exempts vehicle The State Energy Plan calls for conversion costs and the a 50% increase in natural gas incremental cost of a new use by the year 2008. alternative fuel vehicle from state sales and use tax. Revised March 10, 1993/Page 6

State Vehicle Conversion Mandates Financial Incentives RsBu!atton of Alternative Fueled Task Forces/ Vehfctes Committees/Studies North Chapter 738 requires State Carolina agencies to prepare a study of alternative transportation fuel use. Oklahoma HB 1193 (1992) increased a lax HB1S53 (1991) created a credit established in 1991 to Committee of Alternative Fuels 50% for vehicle conversion Technician Examiners costs and refueling equipment responsible for testing, for LPG or natural gas. Tha tax certifying and inspecting credit extends to January 1, alternative fuel equipment 1995, at which time it drops to instal'ers and 20%. promu!gatingerformance standards. Natural gas vehicles pay an annual fee of $100 in lieu of a A 1991 law deregulated the per gallon road tax. There is no sale of natural gas as a vehicle sales tax on sales of compressed fue!. natural gas. Oregon SB 765 (If 31) requires that the HB2130 (1991) expands the HB 2130 (1991) permits HB 3344 (1991) authorized two state Government vehicles be energy conservation tax credit investor-owned utilities to offer studies: (1) A Department of capable of burning alternative programs to include costs of commercial and industrial Transportation feasibility study fuels to maximum extent acquiring alternative fuel fleet customers cash assistance in of replacing its passenger economically possible. After July vehicles. purchasing alternative fual fleet vehicle with natural gas vehicles 1, 1994, the state shall acquire vehicles and fuel. f Energy study to assess only alternative fuel vehicles renewable fuels and cost of except in areas unabfs to achieving state fuel economically dispense alternative independence. fuels. HB 2175 (1991) authorized SB 766 (1991) requires mass establishment of a Public transit and transportation district Transportation Development vehicles purchased after July 1, Program which may include 1993, to be capable of burning alternative fuais. alternative fuels if technologically and economically possible. Revised March 10, 1993/Pa 9c 9 fthtcli Conversion Mandates Financial Incentives Regulation -A Alternative Fueled Task Fores*/ Vehicles CommHttes/Stuc%t IB 1028 11991) requiret 30% of Licensing fee waived for taxis HB 1028 11391) requires the tats vehicles purchased after and for hire vehicles (1991-96). preparation of several studies of luty 1, 1992, must be capable of natural gas vehicles. turning alternative fuels, Natural gas and LPG cars pay an Tcreaxing 5% each subsequent annual fee of $45 in lieu of a per aar. gallon road tax. ling County Ordinance 9891 squires 50% of vehicles purchased in 1992 to use ifternative fuels and 75% in 993.

SB 2 requires the Public Service Commission to develop alternative fuel technology demonstration programs. The law also deregulated sale of natural gas as a vehicle fuel.

A 1984 law deregulated the A 1990 Governor's Executive sale of natural gas as a vehicle Order set up an tnter-agency fuel. task force headed by cabinet secretaries to develop state alternative transportation fuels policy- ^y-ffiy«g^;^,^

Clean Air Vehicles: A Good Business

Norm Bryan, PG&E VP, Marketing DOE/NARUC Nat'onal Conference on Natural Gas Use April 26,1993 7NB23»014Ot/n PG&E's Environmental Goal

"Improve the quality of the environment by leading efforts to increase energy efficiency, develop environmentally preferred technologies, and expand the use of clean fuels, and by conducting all aspects of our business in an environmentally sensitive manner."

PGNB230M24A3 Market Competition Alternative-Fuel Emissions for Key Pollutants 3.5 Reactive Oiganic Gases (ROG) 3 Oxides of Nitrogen (NOx) 2.5 Car on Monoxide (CO) Grams per Mile CO 1.5

0.5

0 Diesel Gasoline Methanol Ethanol Propane Natural Electricity

PGN6230*OS4»3 Gas Legislation and Regulations Drive the Alternative-Fuel Vehicle Market

iTTTJTTTfi rrrrrrrrr nin •IIIIIIII Key Legislation

1990 Clean Air Act • New vehicle emission standards • AFV program

warn National Energy Policy Act of 1992 • Tax incentives for EVs, AFVs, and fueling stations • Flebt AFV purchase mandates and Incentives

CO V ,? 1990 California Air Resources Board Regulations s

\ California Legislation

• ••••-•• :

PQNB23(»0S«2l/S3 Highlights of ia Legislation

CARB Requirements nghter emissions standards take effect in 1994 Mandated Zero-Emission Vehicle sales starting in 1998 Tax Incentives State tax credits for CAVs

f L ,1 Sales tax exemption Directives to CPUC i CPUC and electric and gas utilities required to promote EVs and NGVs CPUC Code (Summaries)

740.2. (a) Encourage gas and electric utilities to achieve substantial market penetration of gas and electric fueled vehicles (research, development, demonstrations). 740.3. (a) The CPUC, with various government agencies, gas and electric utilities, and the auto industry, will work to encourage the use of NGVs and EVs by promoting the development of equipment and infrastructure. (1) Sale-for-resale and rate basing. 745. (b) The CPUC may estabiish an incentive tariff to recover costs and minimize adverse effects on other ratepayers. c o "55 o J3 *B'^i 0) Q

Ol O o o c "35 mmim U 0) Q 0

Comply with DSM and RD&D Policies Non-Duplicative Consistent with Legislative and Regulatory Goals No Unfair or Anti-Competitive Behavior Promotes Competition Natural Gas Creating a Sustainable Market

Phase 90 91 92 93 94 95

Establish NGV Viability mmm

Launch Fleet Introduction m •

Establish Self-Sustaining •BH Market wm The NGV Market - Fleets PG&E is focusing on:

• involving key players • Encouraging manufacturers to produce and support NGVs • Demonstrating and promoting NGVs • Creating NGV fueling station network • Implementing NGV buyer incentives •Obtaining endorsement of environmental groups

PGHB2t76-\9 VK6G2 The NGV Market - Key Players

Automobile manufacturers - OEMs Equipment manufacturers Fuel suppliers i Service providers i Third party investors

PGHB23CW-IZ4/1WJ3 Actual Emissions Results

NMOG* CO NOx

C.A.R.B. ULEV 0.117 2.5 0.6 Chrysler Dodge Van a Results 0.031 2.3 0.05

i Test weight (lbs.) • Miles 5751-8500 50,000

'Reactivity adjustment for clean fuels The NGV Market - Fueling Creating NGV Fueling Station Network

PG&E built, owned and operated

i Customer owned and operated

iThird party involvement • Financing • Marketplace sales/service

PCMB23W-10 4/21/33 (0 o The NGV Market - Utility Incentives

... ,i|jc|||^Es;MSiiiigr).>;;:\.

V: depending^

\ Results - Year 2000 Natural Gas Vehicles

1 Vehicles on Road ...... 125,000

Projected Gas Sales „ ,...... 14.1 Bcf

Emissions Reduction ...... 475,000 tons/year

PQNK309-14/VS3 GOOD AFTERNOON:

THE OEM VEHICLE MANUFACTURER PERSPECTIVE THAT I REPRESENT TODAY MAY

DIFFER SOMEWHAT FROM THAT OF MY FELLOW PANELISTS WHO ARE INVOLVED IN

THE FUEL SUPPLY SIDE OF THE NGV MOVEMENT. BUT I BELIEVE WE WOULD ALL

AGREE THAT GOVERNMENT POLICY AND AGENCY ACTIONS WILL ULTIMATELY

DETERMINE THE RATE OF NGV MARKET EXPANSION.

BOTH THE CLEAN AIR ACT AND THE NATIONAL ENERGY STRATEGY EMPHASIZE THE

ROLE OF ALTERNATE FUELS IN IMPROVING OUR AIR QUALITY, OUR ENERGY

INDEPENDENCE AND OUR TRADE BALANCE. PRESIDENT CLINTON HAS IDENTIFIED

NATURAL GAS AS THE ALTERNATE FUEL OF CHOICE FOR GOVERNMENT FLEETS,

AND HIS STAFF IS PROPOSING ACCELERATION OF ALTERNATE FUEL VEHICLE

ACQUISITION SCHEDULES. THE STRATEGY IS CLEAR, AND IT IS NOW UP TO US -

GOVERNMENT AGENCIES AT THE NATIONAL, STATE AND LOCAL LEVELS - AND THE

BUSINESS COMMUNITY • TO HAMMER OUT THE GROUND RULES THAT WILL

ACCOMMODATE THE STRATEGY.

"HAMMER" AND "ACCOMMODATE' ARE TERMS THAT TYPIFY THE RELATIONSHIP

BETWEEN GOVERNMENT AND OUR AUTO INDUSTRY IN THE RECENT PAST - I'LL LET

YOU DECIDE WHICH TERM APPLIES TO GOVERNMENT AND WHICH TO INDUSTRY.

BUT ON THIS NGV ISSUE, I'M CONFIDENT THAT COOPERATION WILL BE THE ORDER

OF THE DAY.

153 ONE REASON I'M CONFIDENT OF THAT IS BECAUSE THIS TIME • AND I NEVER

THOUGHT I'D BE SAYING THIS - SOME SELECTIVE REGULATORY ACTION WILL BE

WELCOMED BY OUR INDUSTRY. LET ME TELL YOU WHY.

WE CURRENTLY PRODUCE AND SELL A DODGE DEDICATED CNG RAM VAN - THE

ONLY OEM DESIGNED AND BUILT NGV IN THE MARKET TODAY. THE VOLUME ISN'T

LARGE - ABOUT 700 UNITS LAST YEAR. AT THE FEDERAL LEVEL, THERE IS ALMOST

A TOTAL ABSENCE OF REGULATORY REQUIREMENTS PERTAINING TO THIS CNG

POWERED VEHICLE. NO TAILPIPE EMISSION STANDARDS, NO FUEL SYSTEM

PERFORMANCE STANDARDS, NO CERTIFICATION TEST PROTOCOL - NONE OF THE

THINGS WE ARE REQUIRED TO DO FOR GASOLINE VEHICLES.

LEST YOU THINK WE ARE TAKING ADVANTAGE OF THiS SITUATION, LET ME POINT

OUT THAT OUR DODGE IS THE CLEANEST OEM PRODUCTION VEHICLE IN THE

WORLD, PERIOD. CALIFORNIA CONFIRMED THAT FACT BY GRANTING US THE FIRST

AND SO FAR THE ONLY LEV CERTIFICATE - THAT'S LOW EMISSION VEHICLE - EVER

GIVEN TO A PRODUCTION VEHICLE, FOR OUR 1993 MODEL. THE TAILPIPE

EMISSIONS ACTUALLY SATISFY CALIFORNIA'S ULEV STANDARDS THAT BEGIN TO

TAKE EFFECT IN 1998. AND WE DID CONDUCT FOUR VEHICLE IMPACT TESTS TO

SATISFY OURSELVES THAT THE FUEL SYSTEM WAS SAFE - AND IT IS.

SO YOU MIGHT ASK ME THEN "WHY DO YOU FAVOR AGENCY REGULATIONS? ISN'T

THE CURRENT REGULATION-FREE STATUS THE STUFF OF WHICH DREAMS ARE

MADE?' TO A POINT, THE ANSWER IS YES. BUT IT'S NOT ALL GOOD NEWS. LET

ME EXPLAIN. 154 WE DESIGNED THE DODGE FUEL STORAGE SYSTEM FOLLOWING GUIDELINES

ESTABLISHED UNDER NFPA52 - THE CURRENT ACCEPTED DESIGN STANDARD FOR

AFTERMARKET CONVERSIONS. NFPA52 INCLUDES SPECIFICATIONS FOR THE DESIGN

AND INSTALLATION OF SYSTEM COMPONENTS CITING MOUNTING LOCATIONS,

ORIENTATIONS, LABELLING AND SO ON. IT REFERS TO OTHER CNG STANDARDS

INCLUDING THE AGA NGVI REFUELING CONNECTION STANDARD, WHICH AT THIS

TIME IS STILL A PROPOSAL IN THE ABSENCE OF FEDERAL REGULATIONS, NFPA52

IS A DECENT GUIDELINE.

BUT INDIVIDUAL STATE AGENCIES HAVE SOME ADDITIONAL REQUIREMENTS. IN

TEXAS, FOR EXAMPLE, THE RAILROAD COMMISSION HAS ITS "REGULATIONS FOR

COMPRESSED NAWRAL GAS" THAT REQUIRES US TO OBTAIN STATE APPROVAL FOR

EACH CNG COMPONENT AND ESTABLISHES A COMPLEX LICENSING SYSTEM -

COMPLETE WITH EXAMINATIONS - FOR PERSONS SELLING, INSTALLING AND

SERVICING CNG SYSTEMS. IN NEW YORK CITY, THE FIRE DEPARTMENT ISSUES A

DIRECTIVE ADDRESSING CYLINDERS, PRESSURE RELIEF DEVICES, VENTING, GAUGES

AND VEHICLE LABELLING REQUIREMENTS. CALIFORNIA HIGHWAY PATROL TITLE

13 DETAILS COMPONENT LABELLING AND INSTALLATION REQUIREMENTS.

CALIFORNIA'S AIR RESOURCE BOARD ALSO REQUIRES UNIQUE LABELING THAT

INCLUDES PRICING INFORMATION FOR DETERMINATION OF RIDESHARE AND TAX

CREDITS. CANADA -WHICH INCIDENTALLY IS WHERE OUR DODGE CNG VANS ARE

PRODUCED • SPECIFIES STEEL FUEL CYLINDERS {OURS ARE ALUMINUM), SO WE

CAN'T SELL OUR VANS IN CANADA.

155 AND THEN THERE IS THE REFUELING ISSUE. CURRENT EQUIPMENT IN THE FIELD INCLUDES 2400, 3000 AND 3600 PSI FUEL SUPPLY - AND AT LEAST TWO BFANDS OF REFUELING C0NNECT0R1 THE PRESSURE AND THE TYPE r? CONNECTOR IS DETERMINED BY LOCAL UTILITY PREFERENCE, I BELIEVE. GAS COMPOSITION ALSO VARIES FROM SUE TO SITE, AND FROM SEASON TO SEASON.

RECENTLY, EPA HAS INDICATED THAT EMISSIONS CERTIFICATION WILL BE REQUIRED FOR 1994 MODELS - WHICH WE ARE CURRENTLY SELLING - BUT HAS NOT YET PUBLISHED THE TESTING PROTOCOLS. AND NHTSA HAS JUST PUBLISHED A NPRM ON FUEL SYSTEM REQUIREMENTS, WHILE AGA CONTINUES TO REFINE THEIR NGVI STANDARDS.

WITH MANY EXISTING LOCAL CONTROLS AND NEW EMERGING NATIONAL STANDARDS, WE ARE CONCERNED ABOUT DISCOVERING - AFTER THE FACT - THAT WE HAVE FAILED TO COMPLY WITH SOME UNPUBLISHED, UNKNOWN OR UNDEFINED REQUIREMENT, AND - BY ATTEMPTING TO PROVIDE VEHICLES TO THE MARKET EARLY - HAVE EXPOSED OURSELVES TO POTENTIAL CRITICISM AND/OR LITIGATION.

BEFORE I CONTINUE, LET ME POINT OUT THAT MANY OF THE ISSUES I JUST MENTIONED APPLY ONLY TO DEDICATED NGVS. WE HAVE RECENTLY LEARNED THAT GSA REALLY PREFERS 81-FUEL VEHICLES. I WON'T ATTEMPT TO DISCUSS THE SEVERAL NEW CANS OF WORMS INTRODUCED BY CARRYING TWO FUELS ON ONE VEHICLE - I'LL JUST ASK YOU TO PONDER DUAL EMISSIONS CERTIFICATION, FUEL ECONOMY LABELING, SAFETY IMPLICATIONS, FUEL SELECTION STRATEGIES AND SO ON.

THESE ARE THE REASONS WE WOULD LIKE TO SEE MORE DEFINITIVE REQUIREMENTS FROM YOU FOLKS IN THE FEDERAL AGENCIES. 156 SO WHAT WOULD WE UKE TO SEE IN THE WAY OF ENABLING LEGISLATION? FIRST, THE AFV PURCHASE MANDATES ARE TERRIFIC. BY ESTABUSHING A MARKET, THEY MAKE IT EASIER FOR US TO JUSTIFY THE RESOURCE COMMITMENTS REQUIRED TO DEVELOP THESE VEHICLES. WE WOULD UKE TO SEE EQUAL ASSURANCE THAT THE FUEUNG INFRASTRUCTURE WILL BE THERE TO SUPPORT THE VEHICLES - THIS HAS BEEN A PROBLEM WITH METHANOL AFVs.

NEXT, WE NEED TO ACCELERATE EFFORTS TO REGULATE AT THE NATIONAL LEVEL MANY NQV ISSUES WHICH ARE CURRENTLY HANDLED AT THE STATE OR LOCAL LEVEL THE AUTO INDUSTRY HAS ARGUED SUCCESSFULLY IN THE PAST THAT WE CANNOT ECONOMICALLY PRODUCE MORE THAN TWO VERSIONS OF SIMILAR VEHICLES - WHAT WE CALL THE CALIFORNIA VEHICLE AND THE FEDERAL VEHICLE. THIS ARGUMENT MUST APPLY TO NGVs AS WELL. MANY OF THE LOCAL RULES HAVE RESULTED FROM A NEED TO REGULATE AFTERMARKET CONVERSIONS. THIS SHOULD NOT BE AN ISSUE WITH OEM VEHICLES.

THIRD, WE FAVOR EMISSION CERTIFICATION REQUIREMENTS THAT DO NOT PROVIDE CONVERSIONS AN ADVANTAGE VERSUS OEM PRODUCTS. NATURAL GAS HAS TREMENDOUS POTENTIAL TO REDUCE VEHICLE EMISSIONS - BUT THE POTENTIAL CAN BE NEGATED BY FAULTY EXECUTION. MANY IF NOT MOST OF THE NGVs IN SERVICE TODAY ARE NOT AS CLEAN AS THEIR GASOUNE COUNTERPARTS, OR AT LEAST NOT AS CLEAN AS WELL CONTROLLED NGVS SHOULD BE. THIS MUST NOT CONTINUE IF THE NGV MOVEMENT IS 0 SUCCEED.

157 FINALLY, ADDRESSING VEHICLE AND FUEL SYSTEM SAFETY - WE FAVOR

PERFORMANCE • BASED REQUIREMENTS. BY THIS I MEAN STANDARDS THAT DEFINE

HOW THE SYSTEM MUST PERFORM ON SPECIFIED TESTS RATHER THAN A SET OF

DESIGN DO'S AND DON'TS. CURRENTLY, NHTSA IS CHARTERED TO DEFINE ONLY

PERFORMANCE 3ASED REQUIREMENTS. LETS KEEP IT THAT WAY FOR NGVs.

IN CONCLUSION, LET ME RESTATE - NGVs MAKE A GREAT DEAL OF SENSE FOR

AMERICA. SO LET'S GET BUSY AND COME UP WITH A PACKAGE OF SENSIBLE

REGULATIONS THAT OPTIMIZE THE ECONOMIC, ENVIRONMENTAL AND STRATEGIC

ADVANTAGES OF NATURAL GAS VEHICLE FOR OUR CONSTITUENTS, OUR

CUSTOMERS AND OUR COUNTRY.

THANK YOU

158 CHANGING REGULATIONS & MARKETS

CHALLENGES & OPPORTUNITIES

Craig G. Matthews DOE/NARVC Conference April 26,1993 THE MOMENTUM OF DEREGULATION AND INCREASED COMPETITION IS:

INCREASING LDC RISKS AND PROVIDDTO A NEW PERSPECTIVE

CHANGING THE WAY WE DO BUSINESS

INCREASING FINANCIAL PRESSURES & COMPLEXITY

FOSTERING OPPORTUNITIES, ENTREPRENEURIAL OUTLOOK AND CUSTOMER ORIENTATION

RAISING CHALLENGES FOR LDCs AND REGULATORS LDC PERSPECTIVE: RISKS PASSED DOWNSTREAM

• INCREASED END-USER TRANSPORTATION (BACK-UP SUPPLY/REDUCED REVENUES)

• PHYSICAL BYPASS/FUEL SWITCHING

• LONGER TERM SUPPLY COMMITMENTS REQUIRED

• END OF FERC PROTECTION (GAS PRUDENCY REVIEWS)

»—*• • INCREASED DEMAND CHARGES (SFV)

• OVPACITY RELEASE DECISIONS

• TRANSITION COSTS/TAKE OR PAY RESULTS: IMPACT ON COST OF EQUITY CAPITAL & MARKET VALUE OF UTILITIES CHANGING THE WAY WE DO BUSINESS

• UNBUNDLING OF PIPELINE SERVICES HAS RESULTED IN: - SELLING BALANCING SERVICE

- PROMOTING TRANSPORTATION & BACK-UP SERVICES

• PROVIDE CHOICES FOR CUSTOMERS (NPC) - INDIVIDUAL CONTRACTS & GAS SUPPLY STREAMING

- SERVICES RELATED TO CUSTOMERS' NEEDS AND RISK LEVELS

- MARKET-BASED PRICING (VS. TRADITIONAL RATE DESIGN)

• "OBLIGATION TO SERVE" BEING QUESTIONED INCREASING FINANCIAL PRESSURES AND COMPLEXITY

• SQUEEZE ON MARGINS - COMPETITION DRIVEN (GAS VS. OIL, ELEC, DSM/IRP) - REGULATORY DRIVEN (INFLATION ONLY INCREASES, INCENTIVE RATEMAKING, BENCHMARKING, ETC.) - SERVICE VS. TRANSPORTATION (GAS VS. GAS) h* • CAPACITY RELEASE/DEMAND CHARGE RECOVERY - HOW FAR DO LDCs GO? (REBUNDLED OR PREARRANGED DEALS)

• LOWER ROEs, EPS & DIVIDEND GROWTH

• INCREASED CUSTOMER DEMANDS AND SEGMENTATION OPPORTUNITIES FOR LDCs AND CUSTOMERS

• DEPLOYMENT OF NEW PRODUCTS (NGVs, GAS A/C, GHP)

• DEVELOPMENT OF ENERGY-RELATED INVESTMENTS

• INNOVATIVE SUPPLY, STORAGE AND TRANSPORTATION ^ ARRANGEMENTS en

• STRATEGIC PARTNERSHIPS - MANAGEMENT/SERVICE CONTRACTS

• LDC GEOGRAPHIC FRANCHISE EXPANSION/CONSOLIDATION CHALLENGES FOR LDCs AND REGULATORS

• REGULATORY FRAMEWORK - COST TO SERVE VS. MARKET-SENSITIVE PRICING - CAPTIVE VS. NON-CAPTIVE CUSTOMERS (RIGHTS/OBLIGATION) - INCREASED TRANSPORTATION/BYPASS

• POST 636 IMPACT: TECHNOLOGY, MANPOWER & SKILLS

• INCENTIVES TO INVEST IN DEVELOPMENT AND DEPLOYMENT OF NEW TECHNOLOGIES

• IKCENTIVE RATEMAKING (PROPER INCENTIVES FOR CUSTOMER & COMPANY) • DEVELOP OPPORTUNITIES FOR GAS TO SOLVE AIR QUALITY PROBLEMS CHALLENGE

TO MAINTAIN:

• FINANCIAL INTEGRITY • CUSTOMER SATISFACTION • MARKET POSITION a>

IN A MORE COMPETITIVE ENVIRONMENT "Risk and Reward in Natural Sas" Comments of Commissioner Branko Tersic l Ener?iv Regulatory Commission at the DOE/NARUC Conference On Natural 6as Cansumotion New Orleans, Louisiana April 26. 1993

One f^esis't cf recent developments in the natural gas :nccstrv . fro* developments in both regulatory initiatives and cnananq business circumstances, is a re-evaluation of the •"iSts SPC rewards of" the various "business services" offered bv :o*n 3ioeline= and local gas distribution companies (LOO.

"r-seitjona: DUO1 IC utilit-. regulation has imDl icated an 3v©~sl! ria- m terms of risk of return of capital *eeore™i5ttion over economic ' its and prudence reviews) and tne -jf." w* *$*>...rn on capital ("fair" return on equity) • While tms mav no\ se the most eleoant statement of the arrangement, ;^*s ~aint r,c? ^9 MOD is tnat, unoundling, technology, .«=sui' .5"':^n s'va m*r\ • ©ts all ars splitting the traditional ousir>5s = s into .uultiole services. Some of these services are twia* 7—ers- 'JV incsre than one provider in some markets, and o"~er serMcss msv soon o= offered competitive!v.

T;--.5 'eaas to a Question, not infreouentiv found in utilitv r=au' st:cn, of new to treat -Tionooo'v and competitive services c'-e'-sn ;,v tne 3?i>5 ohvsical and business sntitv. Further. ! ,«f:r; -ns ''5=iu ..

==•-•. ;•:?;. T.-,= r'.'5-aroers of oinelines will now take the risk of . ano :="-sfit -'rcm the rewards of' aas SUDDIV acquisition.

-~ -"* -.sis .eve', loca: gas distribution companies still ?;a.5 ^^^ aas ac-uisition obliaations and sssociated risks for

»-,B:>- •-.->-=' ;j= customers. i.arae industrial and commercial :i:=-"='-s, i- ?i"st .;urisiaicr,ion=, nave asked for and been =r--- = ; =: «fijo~:or»s from acHaatian to buv from the the LDC's hev t^us ~av

167 In a tew jurisdictions. California and Ontario for eKamole. residential customers nave, under certain soeci-fic conditions, s^r; allowed the right to assume their own gas acauisitxon ••*:sr . This >s a trend which should soread. There aooear to be •5'.'."icient gas suoolv providers willing to serve residential W'sti. Customer gas acauisition would remove the risk o+' v-DCs needing gas suoolv portfolios (under regulation) and would e':.^:"

5>ectic = raise a number at interesting Questions. Can residential customers buv gas supolv on their own7 Would -esicsertis) customers be aole to evaluate competing gas supolv o-^*srs"v What if no one offered gai SUPPIV? What about consumer T<-5U>3"* what about ''rel iabil itv" of gas suoolv?

"hese Questions are onlv "interesting" in the sense that wni'sQ thev are "new" for natural gas supolv. thev »re not new -?r residential consumers -for manv other purchases of eausl or 3r»s;er costs. For some families monthlv tele?3hone bills, 3550Iii » bills, food bills, medical bills are at least at 'avels similiar to the gas suoolv purchase. Svstems of cosiness licenses, consumer fraud laws and oossiblv some new -SC reaulatorv procedures and rules mav soive all these oroo". ems. certainly to the level of other purchases. On a oarTicu!ar issue, it is suggested that "reliability' of gas 3uoo*\ can be o-fferea as a service under regulation (backup -ate=' or under competitive market situations (divertible 5uocl\ or "one dav" gas suoolv services).

T'ce oas suoolv "risks" are shifteo off the svstem of -«rcu". stior. ana into ^.he market regulators can concentrate on t^e issues raissa bv regulating transportation and related S5o,icgc. The unbundling of gas transportation services :'-35"=Q onto tne FERC jurisdiction aioel ines will out pressure cr -DCs ?na state regulators to look to "unbundled" on and related services at the LDC service level.

It is suggested that the results of demand side management rsi* and least cost planning programs will lead to conclusions tr-st anor assumed "levels" of service mandated bv regulation are not necessarily appreciate for customer needs and wants. ~ct- example it is assumed . bv regulators and utilities, that f: ' "95;3ential customers need or want the same "rel iabilitv" -^ "zvs'\ itv of service" offered at a single tariffed rate. "~:= ,nav not oe true. Some residential customers mav be o^tsc:1-,' willing to accept "interuotible" natural gas service ?t tne sosrooriate discount from the rate for 100X firm service -or aoth suoolv and transportation. Earlv in the 1970's the suztor- -sad. for example, "oartialllv" interruotible electric 168 in tho form of an sloctric water hoater service 1 imitor with a month] v b;ll credit.

Future natural gas regulation and business planning should look to snrmfcing the residual monopoly while using "oerfQrmance" and "incentive" rat©making techniques for the residual monopoly to increase consumer benefits bv encouraging and rewardinq efficiency. Risks

After nearly a Quarter centurv in regulation and the uti'itv industry I conclude that comoetition is still better than monoDo)v and that today's predominate system of cost of service regulation can be relinauisned to carefully crafted forwara looking regulatory svstems. It is my opinion that uraqros'jwe state regulators, with their recent experience of •^oquiating in an environment of racud technology innovation and related '.mound 1 ing of services in the teleohone industry, mav be icea'lv suited to. lead in the apolication of the lessons in dealing >vith now issues at risk and reward in the d anergv inaustry.

********

189 NATURAL GAS PARTNERS. L P. H» KAtT PUTNAM AWCHUR H. CONNECTICUT OMM Tft MMM %fmm

DOB/HXRUC MTIONAL COWTBRINCR OK MXTTJUXL OAt D8S State Regulation and Market Dynamics in the Post 636/Energy Policy Act Era Panel: Financial Dimensions to Changing Regulation and Markets

R. Gamble Baldwin New Orleans April 26, 1993

* OILAWAKC kSSlTCD »AftTNC*tKI» Ladies and gentlemen, I feel like a ghost at this upbeat feast—at costume drama specter, who moans Mwo«" and "doom."' 3 regret it, but I cannot share conferee convictions that we havi ample time to refine rational Order 636 solutions. Downplayinc urgency is a treacherous lullaby when demand growth is threatened by slipping U.S. gas deliverability. The luxury of gradual problen recognition followed by digestive regulatory lag is, like risk-fre« distribution, of the past. Communication between gas industry segments has always been weak., particularly between unregulatec and regulated elements. The further downstream one operates, the more remote becomes understanding of upstream conditions. The same deficiency affects regulators. This is particularly unfortunate as 636 expands state commission influence from its owi jurisdictional burner tips back to the unfamiliar wellhead. Ii light of this, my most useful contribution to these proceedings ii to explain why an upstream investor/lender like Natural Gas Partners (NGP) shies away from financing regulated projects. This prejudice, I might add, is strongly reinforced by 636 change, whict by imposing demands on management skill, will separate sheep fron goats.

NGP is active in three financing arenas: • Provision of venture capital and/or mezzanine financing to unregulated gas-relatod projects (private placements) . • Temporary investment of our cash in publicly-traded energy stocks and bonds. • Raising new equity capital and negotiating credit lines. NGP also devises exit strategies for our mature private placements (initial public offering; merger; sale; et al.). We could not b« more sensitive to influences affecting financing. As for my remarks, they divide in three parts: • Order 636 and state PUC (Public Utility Commission) power extension. • NGP investment areas and how each is affected directly or indirectly by regulation. • Speculation on the future outlook for natural gas. Order 636 - The Order is described as leveling a playing field, stood it on end is more like it, for all pipeline services tumbled from their old bundles. Now, regulated and unregulated acquirers scramble to pick up the pieces. Participants range from producers

171 to LDCs. With increased market emphasis on critical mass and credit-worthiness, siae and multiplicity of services are keys to profitability in the post-636 world. Obviously, a lot of 636 questions remain unanswered. Evolution of 636'3 implementation, will resolve some, and the outcome of its court testing will eventually answer ethers. Despite these elements of unpredictability, Order 636 holds immediate implications for the financing of all gas industry segments. Segments furthest upstream (production; gathering; etcetera) may be favored. Downstream, regulated segments, notably distribution, are less so, though clever managements can still find paths through 636's mine fields to exceptional success. None of this has modified thes fact that with interest rates low, downstream stocks, which pay dividends, are popular with income accounts. Such popularity is, however, fragile. Look bayond the current trading picture to 636 changes affecting regulated operating conditions. There the greatest concern to industry and finance alike stems from a power shift.

The Shift - 636 transfers responsibility for firm customer supply security from pipelines to LDCs. FERC sheds security oversight, and state commissions assume it. So? Clearly, on a business level, LDCs face new operating expenses and risks. Gas supply is dicey business, for periodically, even the most expert buyer cells a market turn wrong. The real threat though is the broadening ot PUC power. Supply oversight expands the power of state commissions to make decisions that affect our gas industry nationwide. FERC'S performance has hardly been flawless, but its rulings reflect federal policy and appellate court supervision. PUCs, which come in 50 regulatory flavors (Alabama to Wyoming), must focus primarily on their individual state energy considerations—not on national needs. Moreover, state commissioners vary more in experience and sophistication than do their FERC counterparts. Mix, shake well, and you have a recipe for chaos. Oh, I don't really predict chaos but problems—definitely. Here is one sample problem from the past and two from the present: • PUC least-cost gas purchasing policies damaged pipeline financials. Additionally, they depressed gas wellhead pricing and thus exploration from 1984 on. I'll elaborate later. • Currently, PUCs in coal-producing rt*t»s obstruct coal-to- gas switching for electric generation. State employment preempts federal gas use objectives. • Before 636, firm pipeline merchant contracts, which met NGPA standards, helped insulate LDCS and electric generators against PUC second-guessing of their gas purchasing practices. No more. A PUC can Monday morning quarterback to its heart's content and penalize its LDCs on ex post facto analysis. Other panelists who served on the giving or receiving end of 636, have covered the Order thoroughly, so I'll step and pass to my n«xt topic: NGPInvestments and. Regul_at.i_QjQ We are invested in production; gas gathering/marketing; and contract drilling. Each is affected directly or indirectly by regulation production - NGP h>c; invested funds in several, gas-oriented, small producers active in various basins on and offshore. We favored buying production over drilling for three reasons: • Easier Financing - We can borrow roughly 50% of SEC value against producing reserves. • Earlier, Investment ..Rec_p_very_ - Drilling is riskier, blots up equity, and discoveries take longer to bring on line. fijJEL^E-^ErX1^ ~ FoE" years, reserves in the ground have sold below their replacement costs The Ma|n Cause - The NGPA plus subsequsnt. federal and state regulatory action. Xhje^xg.nJL-.Sjjgup_nce - The NGPA triggers a drilling boom, producing excess deliverability; FERC Order 380 guts pipeline minimum wills; PUCs push cheap spot purchases to the detriment or long term, pipeline supply contracts; the alternative minimum tax cuts producer cash flow. The Result - Years of low, average gas wellhead prices; depressed exploration; lack of reserve replacement; and falling deliverability, a major worry best covered under my Future Outlook For Natural Gas. Today's higher wellheaa prices are modifying NGP's strategy. We still emphasize reserve purchases but are also drilling more low-risk prospects. Gas Gathering - Our second investment area is hot. A number of gatherers have performed exceptionally, and such facilities command stiff multiples. Equity and debt are relatively easy to raise for unregulated gathering systems. Wall street loves them, and so does NGP, but buyer beware. Gathering takes more skillful management than is apparent. It is easy to overpay and under-recover. Systems in federal waters and some onshore are subject to FERC and 636. Other facilities are unregulated, but there is always fear that FERC or producing state PUCs may assume jurisdiction. Paradoxically, operators dread the paperwork and unpredictable ruling-s more than margin squeeze. Competition usually takes, care of excessive service charges. Whether consuming state PUCs eventually influence qatherir.g rates depends on how far they go to control their LDCs' delivered gas costs.

IT;* ra Ovu p_j_x,;.»il^ "* ^"'i^d invor.troont nectar in enjoying modest profitability--ait; laar.t .i^fGhoro-. Marino day rater, finally contribute to the bottom liuo, but onshore activity is pathetic, Gas regulation only affects drilling activity through its influence an wellhead pricing. However, there are plenty of other regulatory authorities "that raise the cost and/or risk of drilling. Soil, air, or water contamination can be subjects of enforcement criteria that way change at agency whim. The same is true of workmen's compensation and other insurance as well as safety rules. Some regulations have sound bases. Others represent misconceptions or overkill. For example, in one state jurisdiction, a shallow well costs more than twice as much as drilling the same well in contiguous federal waters. Now what of the Future Outlook for Natural Gas? Multiple questions cloud my crystal bail. Their short list would include two mentioned earlier and one new. €> What will court review of 636 produce? Please Lord, let it not be overturned. None of us should have to face another decade of gas industry confusion. • As FERC regulation dec lines, how deeply will PUCS invade its former turf? And with what affects? And most important... <• Has excess gas deliverabi.l ity really vanished? If the Bubble is history, our nation is once again en the verge of paying for tax and regulatory policy that made reserve replacement unprofitable. Shades of the '70s! There is the off chance that the 92/93 winter and '93 spring are following anomalous patterns similar to last year's. That is: unusual timing of cold waves leading to unusual storage withdrawal patterns and subsequent reinjection difficulties. When buyers get worried, prices respond fast, whatever the season. Price downswings can be equally precipitous. But if supply/demand is really at a level that makes storage reinjection an annual struggle—what then? Two disturbing thoughts: 9 '93 gas prices are the highest in years. Put signs that confirm supply shortfall would boost further demand pull. Question - How long before Congress rethinks decontrol? * Fact - Drilling cannot be accelerated fast enough to hold gas deliverability at present levels, much less increase it. Since 1983, rig inventories and rosters of experienced personnel have dropped by an estimated 75%. We have neither the rigs vest the manpower to do the job. Build-tip would be too slew and passably, hard to finance. And don't count on Canada to bail us out if they are having cold weather. They could not have done so last winter, thcugh the difficulty traced more to well freeze- ups than to deJiverability shortfall.

Some may wonder why, with gas prices up, there is no corresponding surge in drilling. The Explanation - Battle fatigue.* As early as 1984, dreamers predicted an end to the price-depressing Bubble. Today, the Bubble's fate is still uncertain, so drilling dollars are still scarce. If they are to understand producers, LDCs and their regulators mus-c keep in mind two E&P (exploration & production) imperatives: • To earn reasonable returns, producers must sell gas at about three times finding costs. • To keep drilling within acceptable risk parameters, producers must be able to predict gas prices accurately enough to estimate the timing of their investment recovery - i.e., payout. High wildcatter failure rates prove how difficult forecasting has been during successive years of unstable pricing. I once believed that a new round of long term supply contracts was needed both to provide peak season security for firm customers and to damp seasonal gas price volatility. Now, I'm less certain. A mix of contract maturities (none really long term by pre-Order 380 definition) could serve the purpose, for the gas industry is playing on a differsnt field. Pipeline de-bottlenecking and better storage use vastly increase shipping flexibility. Also, short "term supply markets art: efficient. Hedging, swapping, and indexing are evolving fasc and offer some forward price protection. Regrettably, some PUCs consider hedging to be a form of gambling on price swings, and they would penalize their LDCs for wrong price trend calls. Today, only cogenerators must sign up long tei supplies. To be competitive, their plants, need extended-term loans, which can only be obtained with predictable cash flows. Don't expect lenders to soften that stance. They know regulators can change ground rules at will. If at several points in my remarks, I have cited this propensity for regulators to weathervane, it is because it is a matter for serious concern to both operators and their financing sources. To be fair, regulators are in a difficult position. For as long as I have been in business, U.S. energy policy's immediate aim has been: Keep voter energy costs cheap NOW. The policy is painfully short-sighted, but colored as small consumer protection, it is politically sensitive. With the best will in the world, gas

175 regulators have no choice but to work directly under this political gun. They are all too familiar with Senator Everett Dirksen's reaction: "When 1 feel the heat, I see the light." on its surface, the present gas picture is rosy. Gas prices can continue to escalate—at least until they become non- competitive with coal or No. 6 residual. Already there are sign3 of price-induced fuel switching. Gas gets great prass. Blessed by the Administration; favored by clean air rules; touted by Wall Street; gas lustre should survive the off-season. Next winter may be a test though. Many question whether combined deliverability from U.S. production, storage, and Canadian imports can cover protracted cold demand. If customer service should be curtailed, available gas will be subject to the NGPA-mardated priority order. This would immutably confirm the boiler fuel user's distrust of gas as a reliable winter energy source. Congress would react to gas shortages with a witch hunt. Regulators would be called for endless testimony. Large gas producers may be blamed - or Mt. Pinatubo, but uever Congressional and regulatory myopia.

And now a final message. It could be summarized as "Investment interest is the direct outgrowth of profitability." Fund raising from conventional sources (NGP included) depends on the strength of three factors: asset values; cash flows; and most critical—confidence. Lenders and investors must find comfort in both a company's future prospects and its industry's operating climate. Lack of confidence produces tougher debt terms, lower equity values, or worst case—no funds. More than ever before, Order 636 will focus investor/lenders on future gas regulation and its influence on confidence. • Debt rating agencies already evaluate post-63 6 risk in LDCS and pipelines. • With LDCS thrust into increasingly dynamic modes, Wall Street is likely to monitor a broader spectrum of companies and their regulators. Company risk versus reward vrill be their focus. Under these circumstances, gas regulators might find it useful to reread the U.S. Supreme Court's 1944 decision in Federal Power Commission versus Hope Natural Gas. It confirms a Natural Gas Act {NGA) company's rignt "to operate successfully, to maintain its financial integrity, to attract capital, and to compensate its investors for the risks assumed." This formula should be applied wherever regulatory influence falls - on NGA or on nor.-UGA gas businesses alike. Respect it, and funds will surely flow to industry projects.

ITS DOE-NARUC NATURAL GAS CONFERENCE 1993

IRP, DSM AND FUEL SWITCHING PANEL

Commissioner Karl R. Rabago PuHte Utility Commission of Texas

April 26, 1983

Thank you for inviting me to address this important conference. Everyone has agreed that this conference is an important one. It is certainly important to me that these discussions are occurring. Let me give you a little background on my perspective in order to substantiate some of my comments.

I am a Texas Public Utility Commissioner. As such, I represent the regulator of electric utilities. In Texas, the PUC does not regulate natural gas. That is the jurisdiction of our Railroad Commission. As a resuu we regulate customers of the natural gas business.

Ours, however, are not ordinary customers. Our electric utilities make us the largest single state consumer of natural gas for boiler fuel. Of the top five gas customers in the country, three are electric utilities in Texas. Of the top twenty, there are seven electric utilities in Texas.

These customers are players by virtue of their size. They are also players by virtue of their fuel company holdings and by their purchases of electricity generated by natural gas burning cogenerators.

Finally, let me bring you a bit of historical perspective on our gas use. Our electric utilities seem to be at a low point in a very deliberate long term effort to reduce dependence on natural gas as a boiler fuel. I say low point because our

OOF-NARUC Nauiral Gas/NATGAS.DOC/Page 1 utility plans for tho next decode or so rely on natural gas almost exclusively for new generation.

Just twenty years ago, natural gas produced over ninety percent of the electricity in our state. Today, that percentage is down to about forty-five percent. The transition has been, at times, difficult. Part of the effort has fooused on nuclear power plants. The final rate case for this effort, relating to TU Electric's Comanche Peak Unit 2, is currently in hearing at the Commission.

by and large, however, the conclusion seems to be that the transition has been beneficial. Efforts to diversify the boiler fuel mix have been a cost-effective strategy in terms of keeping basic electric rates competitive in Texas. The growth of coal and lignite firing, as well as the cogeneration industry in the state, ha?* provided much needed flexibility in energy generation.

It is the ability to provide flexible response to changing circumstances which is ultimately most important in meeting an uncertain future.

There are a few additional points of common context which also shape my approach to the subject of IRP, fuel switching, and DSM.

First, Senator Johnston made a statement this morning that we have learned that the market is a better allocator of goods (in the economic sense) than government. This statement has gained such currency as to now constitute truism. It is not, however, shibboleth. The market still does not allocate perfectly.

The market today retains three major defects in allocation, which, I believe, are within the jurisdiction of regulatory commissions.

First is the issue of equity. The market's tendency to fail to work equity manifests i .self both in intra-generational and intei-generational settings.

Second is the issue of the environment. The market clearly misallocates when costs to the environment are externalized.

Third, the market misallocates as to the iuture and as to future risk. Important work by people like Dr. Shimon Awerbuch demonstrates that quality concepts do have a place in planning. Stated otherwise, on a simple discounted cash basis, the world is simply not worth saving.

With that said, let me state ciearly that forward thinking regulators agree that market mechanisms are preferred over governmental prescriptions for resource allocation.

Now le me turn to my thoughts about IRP, DSM, and Fuel Switching.

1 ^ ^ DOE-NARCC Natural Gas/NATGAS.OOC/Page 2 On IRP, I was initially inclined to boast that Texas is just now really moving toward integrated resource planning for electric utilities. My boast would be that we are ideally positioned to ensure that our IRP process reflects the benefits of increased natural gas use, if that is appropriate from an energy services perspective. It occurs to me, however, that everyone who is doing IRP right should have built into the system sufficient flexibility to respond to new opportunities.

Gas enjoys in Texas the benefits it enjoys elsewhere, and so it is not surprising to see our utilities planning for gas as the boiler fuel of choice over the next decades. Where gas is considered in IRP settings, fuel price variability should also be addressed. Our commission has made the first good faith step. We have recently adopted a rule allowing utilities to pre-certify long term fuel contracts. We have had no applications under the current regulatory regime, but I hope to see long term contracting options considered and/or used as a mechanism for improving the standing of utility preferences to procure gas-fired supply side options.

I really can't guess how the Railroad Commission will handle its new Federal Energy Act responsibility to consider Integrated Resource Planning. If some of the studies I have seen are correct, gas utilities stand a good chance of increasing sales under an IRP approach which specifically addresses externalities. These studies seem to point to conclusions which are both logically and intuitively correct.

Reading over some of the materials for this conference, I am somewhat pleased to see that gas utilities and their regulators will have to deal with lost revenues from conservation. I am pleased because we will not be the only regulators who will have to face this difficult issue, but also because this issue will force regulators away from the somewhat easy-to-deal-with issue of price to the more important and fundamental issues of value and welfare. On this issue, I personally want the electric utilities to devise the mechanisms they believe will be effective in addressing the problems.

Finally, I am increasingly convinced that we in Texas must find mechanisms to extend our debates and discussions beyond traditional agency jurisdictional boundaries. While I do not advocate elimination of these boundaries through agency consolidation, for I think diversity has value among agencies as well as among people and ecosystems, I know that we must begin to talk. I am hopeful that I could report some success in this area next year.

DSM, as a generic issue, seems to be a practical and logical focus point for confronting the issues of equity, the environment, and long-term costs. The objective goal of DSM programs is the cost effective harnessing of resources which can satisfy demand for energy services, with a specific focus on activities and options on the demand side. As such, DSM is the demand side subset of integrated resource pianning, which, in turn, seeks to provide energy services at the lowest overall cost.

171) DQE-NARUC Natural Gas/NATGAS.DOC/Page 3 End use energy form preferences ore not a proxy for lowest overall cost. In fact, such preferences may well be inconsistent with lowest overall cost, DSM programs from both electric and gas utilities, it seems to me, should be designabJe and designed with indifference to the particular fuel being used to power the end use.

The fuel switching issue falls out from the previous discussion. If gas is the lowest cost way to provide residential hot water, tor example, PUC's have an obligation t« create an objectively based regulatory regime in which electric utilities actively seek to switch electric water heating installations to gas. That regime should allow electric utilities to consider such efforts as incremental installations of supply-side equivalents.

This regime should work in the other direction as well.

In fuel switching scenarios, however, I feel our staff would have several concerns which should be mentioned.

First, the staff would not be interested in supporting fuel switching to gas end uses if gas regulators are not equally committed to the lowest cost, highest efficiency use of natural gas.

Second, above revenue neutrality, in the realm of incentives, regulatory staff will want to see real value for incentives paid and real economic and behavioral justifications for imposing these cost burdens on consumers.

Third, because fuel switching, DSM, or any other IRP engendered activity will be selected on the basis of lowest overall cost, these activities will produce overall benefits. Fair allocations of the burdens of such programs should distributed just as the benefits will be.

Finally, fuel switching does affect two distinct industries which submit two separate bill to customers in our state. As we attempt to hold the utilities harmless from the revenue standpoint, and incentivize these activities where appropriate, some care will have to be taker to avoid double-counting.

In conclusion, whether characterized as reviewers, criticizers, standard setters, obfuscators, protectors of the advocate-less, or shapers of the economy, we regulators are clearly part of the process. We bring concerns such as equity, distributed justice, social welfare, and social COST. We enjoy authority to both delay and accelerate, but we are as conservative and risk-adverse as the utilities we traditionally regulate. Many of us also realize that our long-term goal is to work ourselves out of our jobs to the extent that we can.

DOE-NARUC Natural Gas/NATGAS.DOC/Page 4 And so, os I frequently toil representatives of our regulated entities, there seems to be one good rule, with two corollaries, for dealing with 1RP, DSM, and fuel switching.

Corollary one is that, in the end, we really can't make utilities do anything they don't want to do. Even if we issue edicts by fiat, a utility always has the option of making our initiatives fail.

Corollary two is that we regulators will not accept inaction in the face of the challenges and opportunities in a changing environment.

And so the rule: Solutions to these problems of gas and electric IRP, DSM, and fuel switching must be devised by the industry, and it must be accepted that government will review these proposals for impact upon the broad range of issues comprising the public interest. This will logically include processes in which the public has access.

The result of following this rule will be, I believe, a result that industry, the public, and government agencies are invested in, a result that we will all strive to make successful.

Thank you.

DOE-NARUC Natural Gas/NATGAS.DOC/Page 5 DOE/NARUC NATIONAL CONFERENCE

April 26,1993

Jed Smith Washington Gas INTEGRATED RESOURCE PLANNING

WHY IRP?

Increased Economic Efficiency oo Cost Effective Conservation

Removal of Artificial Barriers

Demand-Side & Supply-Side Equality WHAT HAVE WE LEARNED FROM IRPJ

IQQO We Can Influence Demand !DQDf> Fuel Selection Programs May Provide Benefits ieooO Modeling Capabilities Are Important nf> institutional Barriers Remain r Inter-Utility Subsidies Need to Be Addressed iiiif> Joint Programs May Offer Opportunities We Are Still Learning Residential Energy Survey/Weatherization \ > High Efficiency Natural Gas Boiler/Furnace Incentives High Efficiency Natural Gas Water Heater CO Incentives '* IDDDi High Efficiency Natural Gas Dryer Incentives ThermBusters Clock Thermostat Loans for Purchase of High Efficiency Heating Equipment WASHINGTON GAS1 IRP .... -— .-, ,-— ... •|||;||i|g|| Non-Residential

rN Multi-Farnily Retrofit f>High Efficiency Natural Gas Chiller Incentives 0[i[NHigh Efficiency Natural Gas Boiler/Furnace Incentives High Efficiency Natural Gas Water Heater Incentives EJUL. Cogeneration Incentives Surveys FUEL SWITCHING: IS IT RELEVANT?

Integrated Resource Planning a logical regulatory option for promotion of efficiency.

Regulation attempts to reach the outcome that would occur if there were competition: regulated monopolies to produce output and services at minimum cost — fair return on equity, but no monopoly profits.

All inputs used at maximum efficiency, and overall consumer welfare maximized:

in technical economic terms, the economic inputs are used to equate the marginal rate of technical substitution and the input-price ratio. The differentials of marginal costs, consumer demands, price, and other relevant economic c.iteria are equal.

This is why marginal cost is so important as an economic indicator. To the degree that marginal cost can be 4. used as a guide in setting rates, evaluating investment decisions, and determining options, one approaches co economic efficiency.

What does this mean?

IRP can be a part of the regulatory process in increasing economic efficiency - providing increased value to the consumer. JRP programs based on sound economics can improve economic efficiency.

IRP programs can remove artificial barriers, increase economic efficiency, provide value to the consumer, benefit the community, and impact favorably on company.

May or may not involve fuel selection - based on marginal costs

Underlying economics driving the market. DEMAND SIDE MANAGEMENT PROGRAMS

MARGINAL COST: A KEY ISSUE

Gas Utilities, Electric Utilities

Rate Payer Tests

All Ratepayers/Total Resource Cost Non Participant/Rate Impact Measurement

Participant

PROGRAM SELECTION

Weatherization, Equipment Replacement, New Construction Incentives

Gas Air Conditioning, Cogeneration

PROGRAM ISSUES

Rate impacts

Income Redistribution

Costs and Benefits

ECONOMIC EFFICIENCY AND MAXIMIZATION OF VALUE

Joint Delivery

DSM Bidding PARTICIPANTS NON PARTICIPANTS ALL RATEPAYERS Benefits Benefits Benefits Bill Reductions BR Utility Avoided UAC Utility Avoided UAC (Avg Coat-Gas) Cost (MC-Gas) Cost (MC-Gas) Incentives INC Revenue Gains RG Utility Avoided UAC(af) (Avg cost gas based) Cost (alt fuel) (MC of elec based) Avoided Bill AB(af) Utility Avoided UAC(af) (alt fuel) Cost (alt fuel) Participants PAC(af) (Avg Cost-Elec) (HC of elec based) Avoided Cost (alt fuel equip) Participants PAC(af) Avoided Cost (alt fuel equip)

TOTAL

Costs Costs Costs Participant cost PC Utility UIC Utility Coat EC Increased cost (MC-Gas)

%-Sill increase BI Revenue Loss RL Participant Cost PC (AC-Gas) (AC-Gas) Utilitv U1C Utility Cost OC Increased Cost (Gas-KC based) Incentive INC

Revenue Loss RL(af) (alt fuel) (Avg cost elec) TOTAL BENEFITS - COST Benefits Costs

Participants Test BR + INC + AB(af) + PAC(af) PC + BI

Non Participants Test UAC + RG + uAC(af) uic + RL + uc + mo +RLfaf

IF one takes sum of benefits minus sum of costs

BR + INC + AB(af) + PACCaf) + UAC + RG + UAC(af) - PC - BI - UIC - RL - UC - INC - RL(af)

BR = RL INC = INC AB(af) = RL(af) ??? RG = 8!

Via cancellation one obtains with some reaiTangement

All Ratepayer Test UAC + UAC(af) + PAC(af) uc + PC + uic

IF RL(af) = 0 [i.e.. not squal to AB(af H

UAC + UAC(af) -I- PAC(af) + AB{af), which strengthens the benefit. Non-Residential Gas Chiller Incentives

$200 - $400 per Ton

Eligible Equipment: Double-Effect Absorption, Gas Engine Driven, or Desiccant (Gas Fired or Steam Fired)

Sized From 7.5 Tons to 1,000 Tons Piagitm Nam*; NATURAL GAS CKIU.0I PHOGITAM Oil* ef Evaluation: 04/21/93

Summary at B*wM Ceil Evaluations

PARTICrPAMTG TEST MON^HTICIPAMTS TEST AVL RATEPAYERS TEST

Banafits: Bansfits: Dill RaducUfifM, Primary Fu*l (AC) to Avoidad Coit, Primary Utility [Mt,. to Avoidad Coit, Primary Fu»1 Uli!i1y CMC) to Incantivaa t33.200 flsvanv* Gains, Primary Utility (AC) 1178.083 Aveidad Csit, Altarnata Ft*l !MSi *<53,E£9 Dill Ratfuciisra, AHsfnsta Futl (AC) t155,912 Avoidad Con, Altarnata f uai (MC) S4S3.3SS Avoidad Coit, Altarrsata Fual £-G

Tola! Bsr.at;l* 1251.112 Total Bsnsfits t339.447 Total Banafits t52B.E;B

Costs: Costs: Cosls: Participant Csttt t77.O0O Primary Utility lncn.,«d Cost [MCi tSI.691 Utility Cost Oil) IHKUIII, Primasy Fu«l (AC) 1178.089 Altarnata Utility Incraatad Coit (MC) to Participant Costs t?7.030 bill Incissi»f, A!:srna!a FusJ |AC) to Rayanu* Loll, Primary Uiilily fACj to Ptaary Utility fiscrsaMd Coll JMC3 t£1,SS* Utility Cost to Altarmla Uiilily Incrutsd Csi1 !WC/ to Incanlivaa •33.200 Bavanua Lois. Altarnata Utility (AC) 1155.932

Tola) Cosls t253.089 Total Cosls $270,802 Tots! Costs

Nal Gsnslil 11.023 Nat Banatil $368,044 Msl Sanslil •2C8.J57

Osnafit/Cofl Bil;o 1.00 Bancfit/Cost Ratio 2.38 Banafil/Coll Ralio 3.33

MC » Ca!cu*st;3n Bassd on Utility Margins) Coil MC - Calculation Baiad on Utility IAi

UTILITV COST TEST PHJMAnY FUEl UTILITY COST TEST ALTERNATE FUEL UTfUTY COST TEST

Banafiti: Banalits: Banafits: Aveidad Cost. Primary Fu*l Utility (MCI to Avoidsd Cost. Primary FuaJ Utility (MC) to Avoidad Coil. Altarnata Fo*f Utility {MC! tttS.ttB Avoidad Coil. Altarnata Fual Uiilily (MCI t4S3.3S8

Total S*-M. $403,358 Total Baoaliti to Total Banatiu S4&1.3E8 ^.-,n™. CeiU: Com: CnU: fncantiva* $33,200 Ineantivaa 133.200 IncHithna $0 Primary Utiiily Incraataal Cost (MC) 181.091 Primary Ulilily Incraaaad C«l (MCI $81.S91 Altarnata Utility Incransd Cosi (MO *9 Primary Utility Ceil to Primary Utility Caat to Allarnals Ulilily Cost **> AltarnaM Utility Incjsaisd Cost (MC) to AltarnaM UliKly Coil to

TolM Cost* $114,891 Total Com $114,891 Total Costs 1D

Nal Barwlil $348,467 Nal Banafil itl 14.8911 Nat Banafil M63.351

Bsnalil/Cosl Ratio 4.03 Banalii/Csal Ratio 0.00 Bmfit/Coil fUtio

MC - Calcutatien Bind on Utility Marginal Ceil MC « Calculation Baaod on Utiiily Margin*) Coal 1 MC - Calculation Baiad on Utility Mateinal Cos! AC • Calcufation Basad on Ulilily Avaraga Cost AC - C. 'culation Baiad an UliHIy Avarag* Ccl! AC • CriculAlion &H*d en Utility Avsiapa €&•! SOME COMMENTS ON FUEL SWITCHING PROGRAMS

The programs promote economic efficiency by moving each utility's marginal cost closer to equality.

In cases where utilities are compensated for lost revenues, the utility losing load should be indifferent between fuel switching & conservation programs.

Tend to pass all ratepayers test & non participant test. May lower rates. Benefits may largely flow to one utility, and costs to another. There are several key requirements for implementation oV such key programs. Marginal costs must be well defined. Programs must pass appropriate economic tests: The objective is increased efficiency - not increased load. Any increase in load is incidental to the obtaining of overall lower costs.

Joint delivery of programs may be appropriate -- and can be a win-win situation for non-combination companies as well as combination companies. IRP, FUEL SWITCHING, AND DEMAND SIDE MANAGEMENT DQE/NARUC National Conferonce on Natural Gas Use New Orleans, LA — April 26-2B, 1993 Presentation of Robert L. Ridgley President 6 CEO Northwest Natural Gas company Portland, Oregon

Good afternoon. Each of the topics we're discussing here could warrant its own panel discussion. I'll try to give you the highlights froia the perspective of a local gas distribution company (LDC), and let you ask questions.

First, by way of background, Northwest Natural Gas Company has 360,000 customers in Oregon and Washington. We've had some practical experience with most of the issues raised by this panel. Our utility commissions required us to implement integrated resource planning, or least cost planning, in 1989. We successfully completed our first plan in both states in 1991, and are working on our second.

Second, cost-effective demand side management is required by each state's IRP rules, so we are developing more aggressive conservation programs.

Finally, Oregon formally investigated the economics of fuel switching and endorsed most fuel switching in 1991. I believe this was a direct result of requiring tooth gas and electric utilities to do IRPs.

Let n».e touch briefly on the issues.

194 i Firgt. floes gas integrated,....respurce P^annAnfl[ differ from electric planning? Yes and no. Typical IRP rules are the • sane for both industries. They include all the basics like* (1) requiring multiple load forecasts, (2) determining need, (3) comparing supply-side and demand-side resources, (4) choosing the least cost nix of resources, and (5) planning for the uncertainty we all face.

Where gas and electric IRPs may differ is in implementation. The current IRP framework developed in the electric industry at a time when electric generation acquisition was still fairly detr.-mirdstic. This is certainly not true for gas utilities, and increasingly is no longer true for electric utilities.

In this deregulated climate, gas utilities have any number of gas suppliers from which to choose. They can utilize a number of purchasing strategies. And because of The Federal Energy Regulatory Commission (FERC) Order 636, LDC's pipeline and storage service choices are rapidly expanding. Acquiring firs pipeline capacity is increasingly looking like a commodities market.

The electric industry deregulation has not caught up

JS5 with us yet, but, I believe they are not far behind. In many regions, there is a strong and growing independent power market that gives electric utilities new resource options that do not involve utility-financed plant construction. Once electric transmission becomes "open access" like gas pipelines, electric utilities will likely face the same challenges and opportunities gas utilities do with acquiring cost effective supplies and transportation.

The key for implementing IRPs in this market is flexibility. The gas planning horizon is short and getting shorter. The market may quickly overtake the best-laid plans.

He questioned, when we filed our first IRP, whether we would be able to design a specific supply-side resource plan that would endure as the most cost-effective strategy until the ne;»"t biennial IRP. This was because new supply and pipeline expansion opportunities were developing so rapidly. We acknowledged this in the plan, and specified the criteria we would use to evaluate any resource opportunity in the interim.

Fortunately, we have knowledgeable and supportive commissions and commission staffs in both states. We have been able to deviate from our supply-side plan, with Commission approval, because of changing market conditions. Does Northwest Natural find value In IRP»? Absolutely. Let me list a few advantages. It is a very useful tool for trading off supply- and demand-side resources. It is * gc>d business planning tool for the company. Because our commissions required public participation in developing the IRP, It helped us understand our customers' needs. Finally, XRPs give our resource acquisitions a small rebuttable presumption of prudency. As CEO answering to a Board of Directors, this is very important.

Can IRPs be improved? Yes. Let ae suggest a couple ways.

The first is especially critical for LDCs operating in the new post-Order 636 world. Two developments in FERC policy will impact gas IRPs. The first is straight-fixed variable pricing, and incremental pricing for expansion capacity. The second is the capacity release mechanism. These two policies mean that an LDC's load factor will be very critical to providing "least cost11 service to its customers.

Improving load factor can be accomplished bv: (1) reducing peak demand with cost-effective demand-side management; (2) building cost-effective, off-peak or interruptible loads with creative marketing; (3) retaining high load factor industrial customers; and

107 (4) examining lino extension policies.

There are probably many others.

My point is this, ^arket^na and load building are terms not usually associated with integrated resource planning, but these activities will be essential to LDCs seeking to lower costs. Demand-siae management should include more than simple conservation programs. Integrated resource planning should assist LDCs in deciding which loads to attract, and which to discourage.

The second concern I have is one that all utilities share: the impact of successful conservation programs on utilities' earnings. Conservation programs will play a more prominent role in our resource plans, but at a potential cost to our shareholders. Regulators need to (1) allow utilities to recover margin lost from successful conservation activity, and (2) provide incentives to shareholders to pursue conservation. This needs to be addressed through deferred accounting rather than general rate cases if it is too compensatory to shareholders.

I believe most regulators understand why this is necessary. It is important to remember, however, that an incentive is onlY an incentive if the utility thinks it is. therefore, l would encourage regulators to allow the utilities latitude in choosing their incentives.

f^ ..floes inter-fuel frntetyra^edjresourc e .planning....JooK Generally,, unless a utility is a combined electric and gas utility, there is very little "formal" inter-fuel resource planning. Most states lack the regulatory mechanisms to require independent gas and electric utilities to plan together, and I do not propose further regulation.

However, regulators that require both electric and gas IRPs can consider the inter-fuel implications of planning. The key question for regulators is: how can all energy consumers be served at the lowest overall cost? Regulators can answer this by comparing avoided costs of their gas and electric utilities.

In the Pacific Northwest, the results of interfuel comparisons are very favorable for gas. This is after decades of fierce electric and gas competition. Let me give you some examples.

The Oregon commission formally investigated fuel switching, and found that residential space and water heating loads were served more economically vith gas than with electricity. Based on the study, the commission encourages gas and electric utilities to implement cost-effective fuel switching programs.

In fact, the Oregon coauaissian recently ordered an electric utility to modify its electric water heat load building program so that the utility's financial incentives were available to customers wanting to switch to gas.

And, in many places, depending on electric avoided costs, summer cooling loads may well be more economically served with natural gas.

The region's single combined utility, Washington Water Power, is switching space and water heating loads from electricity to gas as a cost-effective electric demand side measure.

Let me address a more important form of interfuel planning. One shortcoming of IBP is that utilities plan in isolation of each other. In our region, natural gas-fired generation is the most popular new electric resource. Unfortunately, electric and gas loads peak at the same tine. Sizing the pipelines to meet all these loads raises the question of whether we may overbuild capacity. All consumers pay too much when capacity is overbuilt. Electric and gas utilition are beginning to talk to each other about our planning. Tho rer.ultn arcs favorable. Northwest Natural Gar. hc\r, eooprratoci with Portland General Electric* an electric utility In our r.ervice territory, to shar« the cost and use of two pipeline expansions. Both utilities will receive economic advantages from thir. arrangement which,could not be achieved separately. This is the kind of "inter-fuel, integrated resource" planning that regulators should encourage since electric and gar. ratepayers both benefit.

finally,, how do onvironmontal extprnai4tj.es impact IEEs2 In Oregon, we use the phi«ir.e "externalities" to include costs that society incurs but which are not .included in the utility's direct costs. Ur.ua.Uy, these «re the environmental costs of air or water pollution, although there are many forms of environmental costs.

I think regulators should provide for environmental externalities in IRPs. Oregon's 1RP rule has always required utilities to "consider" the environmental impacts of their plans. Oregon now plans to require utility IRPs to examine different resource strategies assuming a range of cost adders for certain greenhouse emissions. This will increase the utility's avoided costs to reflect the true environmental cost.

"'? 1 For example, if an LDCs 30-year levelized avoided costs siuL£iia\l£ including carbon dioxide and nitrous oxides are 44 cents per therm, addling a range of values representing these emissions nay raise the real cost of the resources by 6 to 25 cents per therm. What was 44 cents per therm is now SO to G9 cents per therm on a 3Q»year levelized basis. The concept is the same for electric utilities.

In most cases, adding environmental costs to an LDC's avoided costs means that conseryafrioq wj.ll appear more cost

Effective ^han. jt normally jst

49.. fog. iTVfreyfufrl Fl.an.iiTH? It means that direct use of natural gas will tend to be advantaged. Direct use of natural gas will be preferable to gas-fired generation, which has significantly lower burning efficiencies. So, fuel switching to natural gas will look more advantageous as an electric-demand side resource. And, gas-fired generation will be more attractive than other forms of fossil fuel generation, such as oil- or coal-fired generation.

Having said all this, I urge some caution. Market distortions can be created if different states regulate externalities differently, or if some unregulated fuels escape environmental scrutiny. State utility commissions should feel flPR TO *«3 OU 14PM m Nffi'URflL COS iXG ?2U PS«4

ffsraa to nouaina snviiwxental ctsstii of rasoure:* plftsmlng, but tto»y Mhould b«

allows its ufeiliti«a to »hov that •nvixonaantml cc*t addsrf »ay csraattt pvrvsraion* in tha sarkct. I think tltl« i« a aansibl* approach until a national solution can b* found.

Befora I f^wi«hf lat «• touch on tb« Xdainistratio&'a Btu tax...

'•> A •], E-9SX CU'J 503 220 2564 CH-Q8-93 03:IAPW POOI 10SR2 FROM SHi Oil, TO 02020982213

DOE/NARUC NATIONAL CONFERENCE ON NATURAL GAS USE

Background and Overview of the National Petroleum Courcil Study on Natural Gas

Remarks of Lawrence L. Smith Chairman

April 26, 1993 New Orleans, Louisiana

204 >96tt 04-02-93 li:02AM P00* *03 RHFU, OIL TO 00028962213 P,H5

Good afternoon. The NFC Study on Natural Gas was conducted in response to a request from former Secretary of Energy Admiral Watkins. (Slide 1) The Admiral requested: "A comprehensive analysis of the potential for natural gas to make a larger contribution to our nation's energy supply and environmental goals; to consider the potential barriers that could impede the deliverability of gas to the most economic, efficient and environmentally sound end-uses."

We are pleased to report that natural gas has the potential to make a significantly larger contribution, both to the nation's energy supply and its environmental goals. Achieving that potential will require positive actions by both industry and federal, state and local officials (Slide 2) Over a two year period, 1991-1992, over 200 contributors examined the U.S. natural gas industry from the reservoir to the burner tip. The study team included representatives from all segments of the natural gas industry, as well as end-users and federal and state regulators. Over 30 person years of effort was required. Results from the study have been documented in six volumes and summarized in an Executive Summary report. Copies of these volumes and summary may be obtained from the NPC.

S-97X .„').> 04-C2-S3 II:02AM POOS »Q3 FRjf-l •>«..!. OH. TO 02006962213 P.BS

The study committee formed four major task groups; namely, Source and Supply, Demand and Distribution, Transmission and Storage, and Regulatory and Policy Issues. The Task Groups then formed several special^; suh-^oups to examine specific issues. The study committee formally met 19 rimes to ensure proper integration of the task group efforts.

The Task Group Chairs were Waiter Hontek from Mobil, Mike Morris of Consumers Power, Bill Smith, Sonat, and Rick Richard, New Jersey Resources. This afternoon's panelists are also identified on Uie slide.

(Slide 3)

The principle focus of the four task groups was as follows:

For Source and Supply: Define the domestic resource base and examine import and export opportunities.

Demand and Distribution: Examine and define market opportunities and constraints In all sectors and analyze by ten domestic regions.

Transmission and Sterarsa: Analyze the capabilities of the existing system and determine ilie need for system revisions with changing supplies and markets.

Regulatory and Policy Issues: Examine how the regulatory environment affects tlw operatioHs of the industry and develop appropriate policy and regulatory recommendations at the federal, state, and local level?.

P-S6X 04-02-93 11:02AM P006U03 S0U13 PRtTI fMFU, OIL TO D2HPO«3GG213 P.07

(Slide 4)

Constraints to the use of natural gas were identified by study participants. We also conducted an extensive consultant- led focus group study which included some 15 industry, regulator, customer and manufacturer groups.

Today, our panel will present significant results of the study, including both study findings and recommendations.

I will highlight the four key findings and the two general categories of recommendations in my introduction.

(Slide 5)

The first key finding is: "Natural gas is an abundant domestic resource and can be produced and delivered at prices that allow expansion of the market and continued development of the resource." Development of the resource will require sustained real growth in prices, but at price levels that should enable gas to compete with alternative fuel choices.

The second finding is: "The natural gas market fa increasingly diverse, with new challenges and opportunities." Natural gas has potential growth opportunities, but will face substantial challenges from the other traditional fuel sources as well as improved energy efficiencies and conservation.

Hie third finding is: "Increased reliance on competitive market forces has improved the gas industry's ability to serve customer needs in a diverse and expanding marketplace."

207 *-9"7X 04-02-93 1 1:02AM P007 «03 iO:CW FROM SNFLU D1U TO B2C£2O982213 P.i

However in the deregulation transition, significant challenges to the industry of both potential gas supply and price volatility are apparent.

The fourth finding is: "The gas industry faces significant challenges requiring proactive steps by industry and government."

(Slide 6)

The two general categories of recommendations are:

"Federal, state and local officials need to allow competitive market forces to continue to develop and work/ and,

"Industry needs to make the market work."

Now, our panelists will discuss the background and support for these study findings and recommendations.

208

04-02-93 1!:02AM FQOB *03 • Slfcfel m

From Request by Secretary of Energy June 25,1990 "... a comprehensive analysis of the potential

for natural gas to make a larger contribution .. H to our Nation's energy supply., [and] ..to r consider carefully the location, magnitude and economics of natural gas reserves, and the projected undiscovered and unconventional resource; the size, kind and location of future markets; the outlook for natural gas imports and exports; and potential barriers that could impede the deliverability of gas to the most tJ economic, efficient and environmentally sound u

O end-uses." y 3

IWtl/fl »

.1 Slide Z

Coordinating Subcommittee NPC Natural Gas Study to L. L. Smith - Chairman D. A. Juckett - Govt CoChairman i A. J. Vennix - Assistant M. W. Nichols - NPC Secretary Source Demand & Transmission Regulatory & & Supply Distribution & Storage Policy Issues o W. S. Plontek* M. G. Morris* W. A. Smith* O. G. Richard* r i r-- cr. C. P. Chandler F.E.John R. J. Burns S. L. Campbell

J. B. Foster J. R. Lee W. W. Slaughter F. O. Helntz

R. B. Galvin J.W. Glanville<1)

R. L. Brown** C. F. Belknap** S. C. Voorhees** S. J.Harvey**

o

t ID

u * Task Group Chairman 0) Deceased (September 16,1992) ** Task Group Assistant • Slide 3 K

Study Approach and Methodology i o Source and Supply a - Domestic resource base

- Imports and export opportunities c o Demand and Distribution - Opportunities and constraints in all sectors - Analysis by region o Transmission and Storage d - Current system - Need for new facilities . • § o o Regulatory and Policy Issues - Regulation in the competitive market u - Requirements at the federal and state level

mitn m a u Slide 4

Study Approach and Methodology a o AH study participants were solicited for constraints to use of natural gas and a suggestions for improvement r ro o Input from focus groups (15) on barriers to natural gas and potential remedial action - Natural Gas Industry - Regulators - Customers

- Equipment Manufacturers y

Will* xvxtnt t SI a iude 3 5;

Key Findings from Study f

o Natural gas is an abundant domestic resource | and can be produced and delivered at prices that allow expansion of the market and continued development of the resource re O The natural gas market is increasingly diverse, with new challenges and opportunities o Increased reliance on competitive market forces has improved the gas industry's ability to serve customer needs in a diverse and

<3 *• expanding marketplace o The gas industry faces significant challenges requiring proactive steps by industry and y government Ktvum Slide £"

Recommendations from Study

a O Federal, state and local officials need to allow competitive market forces to continue to develop and work o Industry needs to make the market work

u

IWIW2 u NATIONAL PETROLEUM COUNCIL •- NATURAL GAS STUDY

TRANSMlSSrOfJ AND :h Urn $;«*'!

V

DOE/NARUC National Conference on Natural Gas Use April 26, 1993 % New Orleans, LA V TRANSMISSION STORAQ1TASIC QfiOUP #1 mtfm

#1 The existing system is a valuable asset that plays an integral role in the development of the U.S. energy industry. — r

#2 The existing system can support a growing U.S natural gas market.

HASUC/FIn i*>.'.*''••'•. v .' '• .-,.T ^ '••.:••*••• U1

;L ••^;.:

'••••. , i, '.'..•, New facilities will need to be constructed to adapt to changing supply and market patterns; the estimated cost should not be a major constraint to future industry growth. TRANSMISSION & STORAGE CAPITAL COSTS (1991 $ Billion per year)

>2.6 $2.4

$2.0

1971-80 1981-90 1991-2010 TRANSMISSION AND STORAGE TASK GROUP! FINDING #4

#4 The natural gas transmission and storage system has - and continues to improve ~ the ability to provide economic, efficient, and reliable service responsive -~ to customer needs. • additional capacity constructed and planned

""••'•••'. • 'i • technology • continuing transition toward a more ' ' . ' competitive environment

NARUC/F3B STOTAQE TASK QROUP

#6 The natural gas transmission and storage system need* to further Improve its ability to provide economic, efficient and reliable service responsive to customer needs. historic curtailments of natural gas service complicated, inconsistent, and changing pipeline operating procedures • difficulties in purchasing and acquiring transportation • changing regulation, including unbundling under Order 636

MARUC/F4 TRANSMISSION AND STORAGE TASK GROUP SUMMARY OF FINDINGS

#1 The system is a valuable asset.

** ' '•''•• #2 The system can support a growing U,S, natural gas market,

• • . • •

#3 There* will be continued need for construction; the, estimated cost should not be a major.constraint to future industry growth*

#4 The system continues to improve service.

• • % - #5 The system needs to further Improve service. , ^

MABUC/FIVE TRANSMISSION AND STORAGE TASK-GROUP RECOMMENDATIONS

#1 Incentive Regulation and New Services

. K Cneourftg* deregulation In competitive markets and incentive c . regulation Inttfotf markets where competition hat not been v «ho*m to extot, • fd»terr rr%dug^d costs, increased efficiency and tonovtonovalfvCseTvloes

- - • Deveiop creative and tailored services. TRANSMISSION AND STORAGE TASK GROUP RECOMMENDATIONS

#2 New Facilities: The industry must improve its ability

A. Work with customws

C. Faster praject approval D. Reduce capital-eosts TRANSMISSION AND STORAGE TASK GROUP ••-..'•*' RECOMMENDATIONS .

#3 Reiidbility: The industry should expand its work wtth customers to address specific reliability concerns . • Natural Gas Reliability Council * • improve communication customers, including ' electric utilities'

NARUC/rety TRANSMISSION ANB STORAGE TASK (5ROUP i

#4 Develop industry operating guidelines to make it easier for customers to buy gas

• INGAA/COPAS i '-l ..•••• - / • EDI, OBAs,iPDAs v * * % •••'•'• real-time measurement A. Improve communication of available transmission and storage capacity. ' . ? . B. State regulatory authorities need to evaluate and direct, as appropriate, the unbundling of natural gas sales from transmission and storage services by LDCs and intrastate pipelines in order to further the general objectives of the FERCs Order No. 636, and to encourage the more effective marketing of natural gas services by LDCs, TRANSMISSION AND STORAGE TASK GROUP SUMMARY OF RECOMMENDATIONS

Overall: We need to further improve service #1 Incentive regulation anc| new services #2 New facilities #3 fleliability #4 Industry operating guidelines #5 Access to pipeline and storage capacity

HARUC/BE POTENTIAL F TRANSMISSION AND STORAGE SYSTEM

The natural gas transmission and storage system provides economic, efficient, and reliable natural gas services in response to customer needs, enabling natural gas to make a larger contribution to our nation's energy needs and environmentafgoals. NATIONAL PETROLEUM COUNCIL STUDY ON NATURAL GAS:

REGULATORY AND POLICY ISSUES

Presented by:

Stephen J. Harvey Managing Consultant

R.J. Rudden Associates, Inc.

April 26, 1993 NPC REGULATORY FINDINGS

Federal, state, and local officials INS need to allow competitive market forces to continue to develop and work.

R.J. Rudden Associates, Inc. WHY ENCOURAGE COMPETITIVE FORCES?

Competition and the public interest

Shortfalls in the existing system

Themes for moving forward

AcefViita^ Irtr* • A "NEW PARADIGM" FOR THE PUBLIC INTEREST

"...regulatory policy should be directed toward increasing the number and quality of choices available to buyers and sellers of energy goods and services, without unnecessarily interfering in the consequences of the choices buyers and sellers may exercise."

JfroOOlM

R.J. Rudden Associates, Inc. REGULATORY CONSTRAINTS TO GROWTH

1. The regulatory process is unpredictable.

2. The regulatory process is slow,

3. State and federal regulatory processes are uncoordinated.

4. The regulatory process distorts business decision making.

5. The regulatory process causes industry fragmentation.

dfniCOllS 5 65|R.j.Rudden REGULA TORY CONSTRAINTS TO GROWTH

6. Regulation limits customer choice.

7. Mixing rate making with social policy distorts natural gas markets.

8. The regulatory and policy environment implicitly treats natural gas as a scarce commodity and rewards existing customers or practices at the expense of new opportunities.

R.J. Rudden Associates, Inc.- THEMES FOR THE FUTURE

KSSt

Less regulatory uncertainty

Less reliance on regulation

Less fragmentation and factiousness

More customer orientation

RLB -1022/92 (Slide 1):

This chart shows the primary work groups that we had on the supply side, basically six working groups and some smaller groups put together for ad hoc studies. Three groups focused on various segments of the supply. We chose to split conventional and nonconventlonal gas as well as imports and Alaska so that we could do more detailed work on each one of them, looking not Just at the resource but at the resource and the supply in conjunction with one another. We also looked at three critical areas of importance to the supply: technology, environmental issues, and contracting practices.

t\3 CO t Key Findings

Resource - Vast and diverse Groves with time an technology Rl,B - 1W22/92 tSIide 4):

We have five key findings on the supply side. First, the resource base is a vast and diverse resource base, available boih domestically and from Import sources. Importantly, we beltevs thai the resource base is dynamic and will grow with lime. This is r.ci to say that it's necessarily accessible, all of it, either domestically or import. Nor does it necessarily mean that it's going to be cheap to develop.

ro •i».C"*

Supply dan be competitively available RLB . 1822/92 (Slide 5):

The second key flnding is: we believe that supply can be made competitiyely available, not just for the near-term as is evident today, but for the longer term. There are three prerequisites that are required In order for that to become a reality «%td those are really the other three findings, which are technology, environment, and economic climate.

ro Total Resources Proved Reserves When you look at the various places that gas can come from and the various resource categories that we have, ifs an enormous supply potential I want to compare the small box in the lower 48 states, the 160 ICF, which to the proven reserve base in the lower 48 states, to the resource and potential reserves elsewhere in the world that provide additional potential to meet supply over the long- term. Contrasted to about a ten year supply, if you think in terms of reserve production ratio, these figures put gas well up in the class that the coal people like to talk about with their reserves.

CN3 tii- ]!)

ResQvu roe Dyn a m ics

PROVED RESERVES

CUMULATIVE PRODUCTION

1990 1995 2000 2005 2010 RLB - 10/22/92 (Slide 10):

This chart b included to dramatize the point that the resource base is dynamic. As production continues over the years, we would expect the reserves that are presently available to be replaced by additional reserves brought in from the resource base. We would also anticipate that as time, technology and perhaps price worked together to give us additional experience and additional knowledge, we will also see the resource base itself grow.

a.* Natural Gas Resource Base Lower -48 States

Proved Reserves Conventional Resources Reserve Appreciation New Fields

Non-Conventional Resources Coalbed Methane Shales ' Tight Sands Other

Total Resources Basis: Recoverable RLB - 10/22/92 (Slide 11):

Taking that concept in mind, we chose to portray the NPC estimate of lower-48 state resources of 1295 TCF on the basis iha! we would incorporate some ol that potential for resource growth. Since we were looking at a 20-year study on the reference cases, v/e chose to adopt technology anticipated to be available by 2010 as the basis.

In addition, this estimate has no explicit pries criteria because we don't know what the price is going to be over time. If yen look at particular alternative numbers assuming alternate technology, or specific price assumptions, you obviously get different answers. For instance, if you assume current technology, meaning no technology improvement from today, you would have a figure of sboti! 1C65. If you took some specific price assumption and put around it a few assumptions about how that translates into Tproducibillly and production at that price, you would have other numbers as well.

For instance, if you assume $3.50 price forever, the number would be on *.he order of 825. Taking other more conservative assumptions, you could work your way all the way back down to the reserve base itself. Technology Advancement

Survey of technology trends Drilling cost savings Higher recoveries Survey of R&D funding

III • W RLB -10/22/92 {Slide 15):

1 mentioned technology as one of our key findings and its importance to growth. At the beginning of this study, we entered into a survey of a!J the participants In the study, and looked at 57 categories of technology to get a feel for just how important technology has been, and where it's going to be most important in the future.

Although we didn't try to identify specific technologies and say they're going to occur at a specific time, the genera! feeling was that the importance of technology and the contribution that it will make both in terms of lowering costs and improving recoveries would actually accelerate in the future.

To try to calibrate this and to get more specific about it and utilize it in our modeling work, we also did a statistical correlation utilizing consultants' help on some very detailed data of historical drilling costs. After you separate out other factors from technology such as influence of oil price or influence of rig availability, we found an underlying positive trend in the contribution of technology to drilling costs that averaged about three percent per year. Now that doesn't mean drilling costs are really going to come down three percent per year, but that technology is going to help keep them down as a counter-pull to things like inflation.

In addition, we looked at recovery for both conventional and nonconventional gas and where we thought that might go in the future. Conventional fields already have a pretty high recovery level for gas, so we don't anticipate great impiovt.nent there, but perhaps a half a percent per year. For nonconventional fields where recovery of the in-place resource is much lower, we would expect it to increase something on the order of two percent per year although it will vary by location and resource. Indeed, those numbers are worked into the resource estimate that I talked to you earlier about.

Toward the end of the study, we also did a survey to see if industry was continuing to invest in research and development at the pace that they had been in the past years in light of the fact that there had been some cutbacks by industry and efforts to economize. Directionally, we found that R&D for oil and gas is continuing at the pace il has in the past. So we took some comfort that activity levels are sufficient to at least support the continuation of the technology. Environmental Compliance

Resource Conservation & Recovery Act - RCRA Clean Water Act - CWA Safe Drinking Water Act SWDA Clean Air Act - CAA RLB • 10/22/92 (Slide 17):

We also looked at environmental compliance costs that affect all of our operations in all phases. Listed here are four of the mere critical pieces of legislation and regulation that affect cost for gas exploration and development. Our environmental task group looked very carefully at all of these and at other statutes and tried to define what we saw as the potential for additional regulation, additional cost on our operations over the next 20 years.

They developed two scenarios for that purpose. One, which we use for the reference cases that Larry mentioned earlier, assumed, subjectively that we would live in a world where environmental regulation would be based on a reasonable balance of cost and benefits between the environmental aspect itself, the cost of the application of It, and the downstream merits of gas as a clean fuel. at Now, what we really had to work with here was a history where environmental costs on exploration and producing have been growing at a rate of about four percent per year. Under this assumption, which some of us finally decided to call a "fair shake" approach, we would see continuation of Increase in compliance costs but not quite at that pace.

The alternate scenario assumed that we would not get the benefit of the doubt, if you will, that the batance would shift more towards stringency of regulation. We would experience an accelerating pace of control on this business. Gas Supply Reference Case 1 TCF

Nonconventiona!

1995 . 2000 2005 2010 Kin - 10/22/92 (Slide 20):

These are some of the supply model results. We anticipate by 2010 under reference case one, the so-called moderate energy growth environment, that demand and therefore supply would increase gradually from today's level of around 20 TCP up to about 25 in 2010 or about a 25 percent growth. You can see fiom this chart that most of that growth on the supply side would come from increased imports, primarily from Canada, and increa£es in nonconventional gas. Most of the nonconventional gas would be tight sands.

We do not anticipate within the framework of this study full utilization of the LNG terminals, frontier gas coming in, or North Slope of Alaska coming down to the lower 48 states. Conventional gas would just about hold its own. The makeup of the gas wilhin thai would be shifting toward smaller fields and deeper deposits as the resource base matures. So tht cost of individual segments, including the nonconventional, are going to be higher. The result of this was that price would increase to a wellhead average of about $3.50 per million BTU by the year 2010.

Behind thai Is a growth in the investment pace for our business. We would see oil and gas investments increasing from todays level of around $40 billion a year up towards something more on the order of $60 billion per year the latter years.

RLB - 10/22/92 (Slide 29):

We have four recommendation areas, and I'd like to cover them quickly. One regards state and federal policy implications and industry practice. We believe it's appropriate to base them on the anticipation that the resource base unto itself is not limiting and that supply can respond competitively given the proper environment to do so.

i : RUTHK. KRETSCHMER, COMMISSIONER

ILLINOIS COMMERCE COMMISSION

DOE/NARUC NATIONAL CONFERENCE ON NATURAL GAS USE

PLENARY SESSION: CAPACITY CONTRACTING

NEW ORLEANS, LOUISIANA APRIL 27, 1993

DISCLAIMER: The opinions and views expressai in this presentation are those of the author and do not necessarily represent the views of the Illinois Commerce Commission or other Commissioners. Our topic today 1M "Capacity Contracting11 and I an pleased to acniarat© a panel of ttvm experts in contracting for tooth new capacity and resale.

Before we begin, however, let's go back in time for just a moment and recall the industry a» it was structured just ten years ago.

If this were the summer of 1983 we would be hearing rumblings of something called mandatory "carriage" and we would be debating whether or not the natural gas industry could survive the transportation of customer owned gaa.

If this were the sunder of 1984 our discussion would center on the deregulation that was to take place on 1-1-65 and we would be debating the expected "fly-up" and all the problems that might occur because of deregulation.

If this were the summer of 1985 we probably would be discussing how smoothly deregulation had taken place and we would be congratulating ourselves that no "fly-up" had occured. The FERC Notice cf Inquiry and the conditions which provoked it would be the focus of our discussion.

But this is 1993 and we have lived through FERC Orders on Special Marketing Programs, fondly called SMPs. in addition we have had blanket certificate programs followed by Order 436

2511 and 436 ABCDE which granted pipelines blanket certificate authority for transporting third party gas. Order 451 revised the pricing structure for "vintage" gas; 438 covered purchased gas cost recovery, 490 abandonment of gas sales; Order 497 prescribed the allowable relationship between a pipeline as a merchant and a pipeline as a transporter. And who can forget take or pay and Order 500 Orders 500 A through L Order 528 and last, but not least, Order 636?

what happened in the gas industry in ten years has certainly been a metaraorphis - or perhaps revolution is a better word. Fortunately, I am an optomist, so I will predict that the industry will survive in spite of federal and state regulation.

The purpose of our panel is to help us understand capacity contracting as mandated in Order 636. Over the next few year* I believe capacity contracting will prove to be the most troubling issue in implementing Order 636. So let's begin. (10: IB On a 586 83«5 EXEC I.Wfi QJC02

SUPPLY PLANNING IN THE POST-ORDER NO. 686 KN V1UOMMKNT

PRESENTED AT TflE NAIIUC-DOB CONFEHENCE ONNATUBALGASUSE APRIL as-ue, ifioa NEW ORLEANS, LOUISIANA

LAREYW.BICKUE & CHIEF EXECUTIVE OHKICISK TEJAS POWER COBPOaATION

Iff S/rO

261

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SUPPLY PIANNTNG XN TOE POST-ORDER NO. OSS ENVIRONMENT

PRODUCTION

In the post Qrdefr No. 636 exmronxnent, LDCs are going to have new options. These sew options represent both opportunity and risk. Those LDCs that recognize the opportunities now amiable an*l expand their supply planning function to take advantage of them will be able to:

• create custom supply portfolios with appropriate reliability for each, dnse of customer, and • reduce overall cost to thoir ratepayers. Those LDCs that) view Order No. 636 as only a regulatory change and fail to 1) recognise the fundamental market and technology forces which are driving the process and 2) tak« advantage of thd opportunities provided are likely to see cither a drastic reduction in. reliability or dramatic increases in cost, or both. To quote Eric Hoffer, "In times of change, learners inherit tlie earth, while the learned find theroselvee beautifully e^aipped to deal with a world that no linger exista". I don't think anyone doubts that we are is a time of change, thus it is important for all of us to set aside what we think we knew and re-examine the fundamental issues, firing on an attitude of learning rather than: teaching. Tins is particularly true {for those of us that axe panel members.

Off SUPPLY FLAKWXNG

At Tetjas Power, ^e believe that supply planning needs to focuB on five basic issues: • Supply w production • Swing dolxverahflity • Transportation capacity • Storage • Information systems In each category^ it is necessary to examine both reliability and cost.

713 ^96 6i6£ 04-31-93 09: 1 BAM POO3 *13 04/21/93 08; £0 Wi3 508 0365 EXEC Vttli 8)00-1

It in important for the non-technical reader to recognize that reliability is a qnHntit.aUw number like weight or square footage - it is not a 'fuzzy, subjective concept like iicppinesB*. There is an entire field of engineering that is dedicated to quantification of reliability. This engineering discipline makes it possible to construct different scenarios and quantitatively compare their reliability and cost. It ia ahnoBt always true that higher reliability implies cost (unfortunately tho r#v»rs« U not truel).

Before rational supply planning can begin, the desired level of reliability must be specified. This initial specification of reliability is most often a 'political" decision. For example, in the U.S. Apollo space program, the reliability level that was selected, a 99.9% chance of the astronauts returning safely, wao the single moat important number in the whole program.3 The astronauts and North America;-1 Rockwell designers were perfectly comfortable in living with a 99% chance (i.e. I in 100) that the astronauts would not return. However, the politicians, realizaag that tbis would be a very public program with lots of international attention, wanted to go for a 1 in 1,000,000, or 99.9999% reliability. If they had dropped one decimal place, the cost of the program would have been cut In half, If they had added one decimal, there probably would not have been enough money on the planet to finish the job.3 On the other hwxd, th» ijolilician* «mld not Mvo with thn typirid fwp«riim«ntal aircraft, and test pilot reliability of 1 in 100. The compromise that w*a reached was a 1 in 1,000 chance of failure (or 99.9% reliability). Bach component was designed, tested, redesigned, rotested ... etc., until it reached the correct lovol of sub-component reliability that would lead to an overall mission reliability of 99.9%.

All of this was "precise" science, not some fuzzy, gobbledygook statement like "it can't fail"! Before any effective supply planning can be undertaken, LDCs and their PUCs are going to have to talk openly and honestly about expected levels of reliability for different classes of customers. Obviously, a large industrial customer that is fuel switchsble doesn't need the same level of reliability tut u residential customer who has no alternative to using gas. Also, there needs to be discussion about v?hat constitutes reliability. Does it mean never losing a pilot light. •• or fines it mean ensuring that everyone (including interrupfcihle customers) has adequate gas at oil times? Once the different levels of reliability and the definition of reliability are established, it is a relatively straightforward engineering problem to design different supply scenarios to meet these levels of reliability. The concept of optimization then comes into play by looking at the cost of these different scenarios. An optimal supply plan ie the scenario that moots tho specified levels of reliability at tho l*ut coet.

In order to examine the new elements of supply planning, consider Figure 1A, which shows a "typical" load curve for an LDC. As can be seen, tbis curve is not a nice, uniform or slowly varying load but rather consists of some low-frequency changes coupled with high-frequency "peaks" and "valleys" as cold fronts blow through, loads switch on and off, stc. It should be obvious that there are different types" of gas that need to be purchased. First, there is the baseload gas shown in Figure IB. This is gas that the LDC uses 24 hours a day, 365 days a year. This "baseload" gas is dearly best purchased from large producers that can provide a

1 Ang-fe of Attack by Miie Gray, pp. 168-169

283

7 ! 3 S9£ 6265 0V21---93 t*E»: 2X ®713 506 flaOH RXEC WTB ®OOS

constant stream bf gas from a variety of different wells. It i<* important that this gos not disappear or be qufc off during peak times sinco it IB tho base upon which everything olm ifi built i A second "type" ctf gas is the short-toxin peaks of gat; that are only needed a few days out of the year (Fig;. 1CI Note that this is the goa needed at the time of peak, said thus reliability is veiy importoiat. While it is possible to buy this gas from a major producer, it is likely to be quite expensive. The actual "standby* cost of this "boll or high water" peaking gas to the producer can btj as much as $0.20 to $0.50/MMBTUD.a Thus if the standby is only used one day per year,! the cost would be $80.00 - $200.00 per MMBtuI Producers might be happy with this, but it & not in the beat interest of the ratepayer. Thus the LDC must look for an efficient and reliable way to provide thiB "peaking" or swing deliverability gas. The "bassload" gas and the ewinsj daliverability gas represent the extremes of the spectrum. In between, tliero are different 'flavors" of gaa in terms of re-liability and load factor. Tho successful LDCs expand their supply planning function to include the ability to creoto mathematical and nff models of the different "flavors"'of gas thnt they need to buy, and they will nuvk tjiu luweul coat fllLoruulivta fur enclt uf Lheau levels of rtsliabiEly aad luad fnct-or. (jleflriy, (me effect of dorcgulniaon has bfion to infcroduco wore options and more technology into twe nvn-ket place. This m good for the ratepayer, became it expand* choicas imd lowers cost?.' It does require tho LDCs to develop a much stronger technical capability than has heretofore been noeeaaaiy.

With thin brief introduction to tlxc concopto of the now supply ploimiHg taiiko, lot'o tolco a look at some of the specific undorlyiBR elements.

SUPPLY OR paopucnoN mmfiNft GAS MOLECULES) t Ultimately, all gas molecules corns from a gas producer, Thus, fiere is a natural tendency to so straight to the wellhead to buy the most "reliable" gaa We believe, however, that this is a Mlacious assumption. Consider, for example, the following thought experiment: Is it better to buy gasifrom ... • A single wellhead that is subject to xreeze off and other operational problems; or • A physical aggregation point such as the tailgate of a processing plant or large gathering pysvm where the gas from h. number of diCfbrent pruduvcib and wells come together; or • A major interconnect in the pipeline grid wh^re pipelines reach back into ftmdamontallj' different supply basins (e.g., Gulf of Mexico, Mid-Contiaont, W T etc.); or :

* See Appendix A for a financial analysis of this cost of shtudog la a producing gas welL

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• A Markoti Center, which includes; • an; iatorconnection of pipelines deceasing different producing basins • hi£h-deliverability storage to provide instantaneous operational balancing of flofva between pipelines

• reil-time title tracking to ensure that the gas purchased hag an instantaneous •clkar title'

Viewed in these terras, the answer is obvious and explains why the FERC has continued to support the concjept of Market Centers as a better way to provide the aggregation function that was historiedlly provided by the pipelines prior to wellhead decontrol and Order No. 380. Note that it is tint. Orri«r Nc. 636 that Mmmfitjni th* mendRtory and inefficient aggregation function of pipelines. Since Aggregation is an important (perhaps th« most important) component of reliability, those who oppose Order No. 696 should consider ctreftilly how the function con be il

A aocoad important quoatioa i»... Who do you buy tbo goo from, i,o, io it bottox to h\xy dircotiy &om tho producer, or from an aggregator who buys a combination of different gw packages flrom many different producers in many different regions and brings these dfvtrte paclatgfi to the Market Center? Clearly, the larger producers such as Exxon, Shell, AmooOi Chevron, etc have enough direct ownership of gas (equity gas) to provide a legitimate aggregation function. However, Ihebe pxuduueju account tor well ho* tLuu 00% of all the gut produced in the United States. Thus, not every LDC can buy all of its gas from a major producer. Who is going to provide this new aggregation function? Will it be large producers, pipelines, marketers or LDCs?

A third important Question is... How much of the gas needed on a peak-day can come from market-area storage and bow much must come from the production area? The answer will vary widely fromjoiiQ LDC to another. In aggregate total, however, about 40-60% of t&« gas burned on a pea): day must come from the production area (see Figure 2). This is & very important point Buying gas at a Market Center obviously mitigates a largo portion of th» supply interruption risk, but is very important for LDCs and PUCs to review both the physical and contractual reliability of the "flowing" gas they buy, as a large fraction of the flowing gas will be needed to serve peak day needs. This olao makes a compelling ease for owning or leasing some production area storage. PUCs are going to hare to allow LDCs to own. lease, or otherwise control 'upstream' assets in the production area - particularly storage projects lihat ensure "flowing gas" on peak days.

SWINGPEIJVfcRABILiry (GETTINGftftgf Mff f,^^T JTfF^ WHKV yny NRF

It's not enough ti just buy gas molecules. It is also necessary to kav© them when and where you need them. As shown in Figure 1A, a lot of the g&s that LDCs consume is cot steady Caseload' gas but is, in fact, "swing''1 gas. Producers (and producing reservoirs themselves) ooiy like to produce at a constant rate (see Appendix A). Ibus there must be Borne mechanism to efficiently convert "baseload* production gas into "swing* gas to match co&camption. Prior to deregulation, tL»» producers didn't: have a cKoica. Tfcioy waro r«quir«d

713 596 63SS C4-2I-93 09: ISAM P006 Hi 3 0*<'r21/«3 00; 23 f*H3 Sflfl 83«8 KXEC MB '81007

by regulation to (provido "free* swteij* gas to the pipelines. Gas was (indicated to a specific pipeline, and wk«n tho load on the pipeline diminished, the producers were required to shut- in their gas and ^ait until the load increased on that pipeline again. Next to eliminatingting mandatory aggregation by thepipelines, tfte second most important change that has occurred is that producers can flow their gas at a rate that w economically optimum for them and theyhey can charge par providing 'swing'. This was effectively accomplished by Order Nos. 436 a]id 500.500 The full effect oi this change has not yet been Been. Deregulation has allowed producing reservoirs Co be iJsad much more efficiently, thuB extending Che "gas bubble". Producers are still giving away iswiug" to sel molecules, but thi» will change when the bubble produced by greater efficiency in reserve use 3s depleted (see Appendix B). Unless a better "mousetrap'' is found, the mat ket value of swing deiiveiability will approach ita true cost to producers - $0.20 lu $0.S»/MWBTUI>.

Aft«r a greag t deal of analysiy s with Saodia National Laboratories, Gas do France and oeveral uuiversitiwi , wo HwH o cond\idod thah t clearly the moitt cofitnaffective wayy to pprovide thia temafomuition team TidTwiflftiond" " prodaotiodi n to "tf"emntf ooneuinptjoj n io throughh h thhe wm off nalt Btoago reservoiri. Salt storage cnvities are iust huge, •underground gas bottles. Since ther* Is no flow of 0U« through » porous material, M in a Cwditionml utorago raswrvoir (3«« PJ0ure 3), the gas can be|xoccted and witlidrawa very quickly, Figure 4 shows the actual operational injections and withdrawals from thw TPC salt storage project at the Mow Bluff Market Center. As can bp seen during a period of cine year, there are very fewday s in which there wssn'fr. tint, iryftfition nr withdrawal. ThftTft BW somft perioiiR of very large withdrawnlR PJH well as multiple revexsals from injection to withdrawal during a single dqy. It is interesting to compare Figure 4 with Figure 1, to see how the short duration "swing" needs of LDCB are easily handled. Tjhese salt storage projects can provide this service for 10 to 20% of the cost of providing this qhort interval "swing" by turning wells off and on (if that were even possible at this rate). TRANSPORTATION f CAPACITY KEALLQCATION) Capacity reallocation provides a unique opportunity for LDCa to greatly ^1*1^^ their reliability without significantly increasing cost Consider, for example, Figures 6 A-C. If an LDC was served primarily by a single pipeline as piiown in .figure fiA, the ability to release Boioa of that capacity and replace it with capacity from the second pipeline, as shown in Figure 5B, and utetream capacity, as shown in Figure 5C, can greatly enhance reliability. Figure 5C ahows chat the probability of Mure has bean reduced by a factor of 350. As you can see in this case, just the simple ability to trade a fixed amount of capacity on one line for the same amounfi of capacity divided between two lines and/or upstream capacity results in a arMtnni.ii; iuvmaiio in Qia overall relialiility tui seen though the eyes of AH LDC. In feet, it; is possible that the reliability of each of the individual pipelines involved could dramatically decrease and the jLDCs could still retain higher reliability prior to deregulation. Notice ebo, in Figure 5C, how the addition of a Market Center in one of the pipelines helps reliability. This ia why it is {important to be able to have the flexibility to move from 000 pipeline to another m the production area.

)

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There is a great ideal of confusion about the different types of storage. There is a tendency to confusa production-area storage with Bjasrkek-area storage. The two we quite different, and have very different functions. The production-area storage has two primary functional

1) Force Majeure backup, as described above in the section entitled ^HPP)y or Prpduction (Buyiap G&B ftfolecufefr). and

2) Low-cost "swing1 gas, as described above in the section entitled fiwfflg Dtfliverability CGffttfaf Has Molecules When You Need Themi

Conventional, rctoirvvu' t»Uirtigti lu tUo auuket area (the type that has mostly been built in the U.S.), serves several different Junctions. First, it becomes a surrogate for pipeline capacity. Qm cam ha luovejd dwing ©ff-pewk times an fcho pipelin* and then redclivtred during tu2>«a of peak deiasad to supplement the peris, capacity of the pipeline. Note from Figure %, however, that no(t oil peak doy loado oan bo root from markot croa urtomge. Thtt morpholocy of the overall pipeline system and the relatively poor deliverability chartctorift-r1 sujrket nrca ro&^rvoir or oquifftr Rtonigo m«ana thtt p««k lotu&a cunnot b* m»t wiili y xoarkot-aroa atottago. The problem »that 95% of nurkot wea Rtoragi nquirM T«ry Iwrgt inv«ntoii*8 of bojtli working #u and pad fas in order to sopport a nnft of dnlhwrahiUty. Fnr example, to create 1BCFD of deliverability requires somewhera botwetn 40 and 80 BCF of worldztg gas and »n equal ansount of p«d, or hflwt, EAR. At $2.00/MMBtu fflr working and pad gas, this translates to $160 million to $320 million dollars, or about $0.20 • $0.80/MMBTUD. AIBO, it takes 40 to 80 days to withdrew all of the working eas from atorage. Obvioualy, thia makes it difScai} to xeepond to short duration load or price swings. Thus, it if important in tfie design of thel supply portfolio to look at the different load duration carves that the LDC is trying to meejt with storage. One type of storage may provide 160 days of 'teaaanaT storage. This type of storage is most suitable for simply displacing line capacity. Another "layer" of storage would deal with, the shorter duration peaks of perhaps 30 to 60 days duration. Pmally, there needs to be some type of storage, or peaking Buppry, that allows the utility to meet snort peaks that last only a few days. It is very inefficient to we one storage field or one type t>f storage to meet all of theBe different performance requirementa Gearty, as we go forward there will be a need to diversify the type* of storage that one nas in ordtr to more efficiently match the duration of various loads with the specific performance of storage. Tte.olo "one aiae fits all* isn't the moeL efficient way to package storage and will probably not survive the realignment of LDC supply portfolios. Just looking at tie storage projects that are available In the UJS., one would guest, chat we are grossly overbuilt on the long-term, slow, seasonal storage and do not have nearly enough 'peaking' storage. Remember, in tbe past, much of this peukuig avtvivo wwt provided by turning producer*off d on in the production area for "free".

Pip elmes are generally much further along in analyzing the different types of storage that will be needed, in thefutur*. (Remember, the pipelines have boon living without their historical •*rs«" swing rights for approximately eight years, by Order Nos. 438 and 451). Note Out many of the pipolinos aro holding "fir* sales* to quickly gst LDCE to buy, lease or othetrotnn acquire their "non-eesential" (to semce or profit?) storage fields under the guilt of "unbundling* ~ <&wat «mptw!

1 S3 596 6365 04-21-93 09,-ISAM P008 #13 soa satia mm im SUoot

Another eartromply important issue with respect to storages is INVENTORY PIWCE MBK Prior to dcccvuCToI of wellhead prices, gas prices wom GxaA by tho govornwiBnt and held constant far lonfr pmiodR of timo. When gns was injected into fltorage, there were "carrying coata" (i.e. the interest ©» the money vaed to pwchewn th« gi»»), but thorn WM no rink th«t pricas would ehdng*. Now. prices change daily and even hourly. For a company with 100 BCP of stored Rijs,« $0.S0 define in price translates to B $50,000,000 losa. GAAP Recounting ruKss hsvo mHsked fliis sitiihtv n. AB long as pipelines had foil pass-through CAcct. 101), they did not have to inarlv-to-marJcet Now, it appears that pipelines may have to begin marking their inventory to market - this will encourage tho pipnlines to let LDCs lease or me storage on an unbundled basis. PUCs need to focus on the issue and decide how much inventory pricn risk r.ho LlVls will undertake on haiuilf of the ratepayer and examine WHJTH to mitigate or reduce their taveotory price risk..

Tho koy to miryivnl in tlio pofit-Ordw No, G3G crtviroiwaonfc ic iiiforamatjon h«nellinff. It rioefin't matter llow much monoy you invrst in paying |jafl inventory cliaxgofi (GICs), ltttnng stomgo, paying promiuma for reliability, cte. Unless you «m jjTove that you own the gas »t tho moment a crisis is occurring it io very \ikvi\y that your £«s wwl be diverted and all of tho premium costs tjnnt wor« paid for reliability will have been wostcri.

The critical isaufc is being ebio to track tho title chain in realtime. Tlie firadamsntei problem is that the pipelines do not have conU/"!tuaI relationships witb or accoee to the information needed to estabhsa a v^id title c^tain. Figuro 6, for example, shows a relatively "simple" title chain at the fcaUfjate of a mqjwr gathering system. It is important to recognize that Figure 6 represents title transfers occurring AT THE TA7JW£ATE OF THE SYSTEM. The K*U hubu't moved ~ only title haa changed. This is a result of "variouo aggregators (pipelines, producer*, wartf>t.«ra niid J\nf!*;) hnying and reselling gas at this point to balance their "book" or portfolio. Note that the gathering company only has a relationship with tho producers who ship the gas on £h& gathering system. The downstream pipeline only has a contractual relationship with their "shippers". The layers ot'*middlemen" have no contractual relationship •with either the gatherer or the pipeline. And yet, someone in the process has to keep track of all of these tijjc tronr.fere. Consider what Happens, for tuutmplo, whou a singlo woll goes down, as showni in Figure 7. It is necessary to trace all the way forward to eee wbich downstream customers are affected by this interruption of supply Tlio answer IB not obvious unless you have a realtime title chain tracking system such as that shown in Figure 6.

It in jN&aRilv to develop the real-time sj'stcm to track the tifclo chain. Unfortunately, uono of the interstate pipelines have seen fit £0 develop SUJI real-time title bracking. "When the pipelines were i$ the merchant function, they bad K strong dis-mcentivo to developing such a system. Any molecule whose owneraiiip was not, dear wa assumed to belong to tho pipcline'a merchant iunctiau. The burden of prcof was on tho shipper rather than on the pipeline. This hns led to some unpleasant instances of the pipeline's: aiercfatml fwucliou performingat the expense of shippers who had invested in higher reliability than the pipeline ia»rdhsxit ib»A to tho post-Order Wo. GSS environment., \t is gmng tr, hft ahsnlntety ftiwesufcial for suppliers and customers to gain control of their own informatio'a systems. This is what we foresee as tiaie teclmical hi^h-ground that will he battled over during tho Ordor No, 636 period, Tfa 'BO of you who have overs5.glit responsibilities at PUCr. need to pay

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eats€ul nttentioti, making sura thnt whon your JLDCfl invest in GICs, fltowgt, «nd other "relinMIity" premiums, they are also addressing the infonaatum crptems nece&iary to actually get the reliability that they are buying.

An important coaeideratioii for tooth LDCB and PUCs:5 that deregulation implies coiapfltitioru Coinpotition inajjlies winners and Ic-sera, and winners and losera ore separated by differences in physical pBifoHnance and technology, not "regulatory clout*. Thus, it is important tu shifl their attention from just regulatory affairs to regulatory tifaixB coupled wifch physical tmderstendixtg of the grid nnd hho wirimis tefihiucal and ph^mcal eleroanta of supply reliability.

The supply pianjaing function at the LDC level, and the FDVIOW proc«63 at the PUC la going to be v.-ry interesting in the post-Odor No. 63& eavironiojent It represents a h>t cf oppox-tnmtioo anH lota of challoagon. Gonorally opsuJdny, tlioso exsmpaoios tlmt looogaiiei thft value of Market 'Centers, the need for lwgh-a^Uvorahiiiiy swiBg m the prodactiion, area, the nciorl to layer1 tJieir etorofeo, the nend to divoraify their transportation, pdthe.naed to unify supply portfolio v?ith "global information fsystems will ho tho winners in ft pioctuw that now has "both winncvf? mvl losera

"7 i 3 596 63*5 04-21-93 09: 18AII POJO »13 08; 25 588 6385 EIKC WTO (£031

APPENDIX A THE COST 0F SWING DELIVEMBIHTY FROM PROPUONG GAS WELLS Prior to Older F* 486, producers were required to provide "free" swing to the pipeline grid. Subseoroent to thi s Order,', the gas hubbfa has oncmiragKrl producers to continue to give away fines awing in ord*rto soil molecules.

However, as suppjy and demand come into balance, producers mil begin to charge for swing. It its important fo: LDCs and PUCs to underaland how much this swing is worth and where the market for stfrog delzvorability will eventually come to equilibrium.

Consider Figure A-l, which shows a typical production decline curve. Recognize that this decline curve is a function of fundamental reservoir behavior. Gas can (in most, but not all eases), be produc id slower, but it can't bo produced taster without risking damage to the reservoir or wells

When gas is shot in and held, both current and future income are effected. Gas that is not. flowing today is being sold and thus is sot earning current rovenue.

A much mora ira] ortont efltect is the defcy of all luturo revenues. If, for example, guti in ahul in for one (1) yeafr,\ then all future dehverics aro delayed by (approximately) one year. Gas that would nave con produced In the fourth year is not produced uut.il the fifth year; gaa that would have ecu produced in the fifth year is now produced in the sixth year... eta

In order to compi te the economic effect of this delay or shift in the production, and thus the revenue, il is JUBU ;ssaiy to make on assumption shout future gno priccc. If one assumes that gas prices will inc rease at the rate of 50% per year every year for the next ten (10) years, then it, hi best to shut n the gas and wait for higher prices. On the other hand, for modest price escalation foreau ts, it is always better to flow the gas now, even at a lower price.

Once a price fore sast is made, the cost of swing deliverahility is easily computed:

1) Multiply t le yearly production values by the yearly price forecast to obtain a revenue stream;

2) Shift the ] irodiictnnn curve further out in time by one (1) year and repeat Step 1 to get. the shifteil reverse stream;

3> Assume, at L appropriate discount rate and discount both revenue streams to obtain the Net Preseiot Value (NPV) of both streams;

4) The diffejrence in NPV between the two streams, divided by the first year's dehverability, divided by 365 days per year, gives a good apprcfiovnatmn of the daily cost of shutting in gas or 'swing de'iiverabiHty'1

"13 596 63fi 5 04-21-93 09: 18AM PO 1 1 JJ ] 3 21/93 Ofl:25 ©713 5110 0305 RSEC IM 8)012

Depending on a) the drxhne rate of the production; b) tbo escalation rate of Mure gas prices; and c) tho diflctnwt tat&e used t« compute iho NPV'fi of the two revenue stream the result will be between S0.2Q/MMBTUD and $D.5O/3VIMBTUD. This ia the inherent cost to the producer of providing sas-w^ delivmi'bility. Prior tn wellhead deregulation, producers wew required to proviso this swing for froa. Deregulation has increased the efficiency of the grid so mi\ah that it. hns groatJy extended the gna bubble (see Appendix B). *njis Kas bubble has kept pressure or the producers to continue to give away swing in order to sell the gaB molprniios therasexves 0.0. better to give away S0.35 worth of swing to sell $1.60 worth of molecules rather (than to bear a $0.35 loss with no recovery).

This situation will change as supply and demand come back into balance. LDCs and PUCs who fail to take steps to deal with the cost of swing deUverability may incur significant riaka and costs if there is even a slight "undershoot" in peak deliverability vs. peak demand.

10

713 596 6365 04-21-93 OS:ISAM P012 313 .-93 Op; 89 Ofna 598 «3«S BSKC LWD

APPENDIX U TRANSPORTATION EmCIENCjy AND THE CAS UUDDUJ

Deregulation hasi increased fche eificiency of the pipeline transportation grid, which, Jn turn, has increased tb« utilization efficiency of producing reserves. In the long-run, this is good far everyone - producer, pipeline and customer. More efficient use of producing reserves implies loss i&v*&ment by producers f«r a given market size; higher load factors for pipelines and lower oast, to ifche consumer. In the short-run, howsvar, the more efficient use of existing hr.a ejrtcwdcd the "gao bubble" and caused lew«r prices to producers.

To under?t3Ud how iuurewjujg transportation, efficiency can create a aurplua, conmdor Figure B-I, whJeh shnwsoca ••'nadized simpEfication of what haB occurred in the gas industry over the last fc-wj'sars. Prior 10 welttxeadldeiegulation and Order No. 461, each pipeline controlled dedicated reserves, In die ^miiti) oxnmplo shown in Fiffiire B-l, etch of the two "balkanized" pipelines controlled l?,0 unit? of f'.eliwr«bility to aerve 100 unite of peak demand at their market (ie. 20ft reserve nwgin). In thr example, *nd in rniU lif«, th« two mnriretA dtrin'f. poak at the tame time. Tat'j. whik> eachi nuurkot has a peak domond of 100, the sum of the twonmrkets has a peak of vHi'tv 170 unite. Tliu.% when deregulataon of the pipolinco allows (and promots*) free saovameur, of ^o£!irom ono pipeline to another, there are suddenly 240 units of dalivertbility chasii*i;'i 170 unite of total demand.

The two individual "balkanized" reserve margins at 20% have suddenly become a combined integrated reserve margin of -40%. In the ltais run, this is very good because less capital r.eeis to be invested in reserves in order to meed the diversified peak loads in the combined svstem. In the sJiort run, howevnr, a 40% reserve margin means that too much suppfr is chasing too littles market (i.e. the gas buw

11

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FIGURE IP,

FIGURE IB

FI6URE IC

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Maximum Day Sendout — Total 79.7 76.8 72L8 73.4 79,5 87.2 88.4 S5.0 Peak Shaving Facilities 1B 2,8 1.4 35 10 •2.2 2.3 1J Underground Storage Withdrawal 385 44.2 39.7 37.3 3S.4 47.9 44.9 40.5 Regular Production and Purchases 39.4 29.8 31.7 34.7 SB.2 37.1 41.2 43.1 Minimum Day Sendout — Total 13.8 12,0 14.3 14.5 1S.9 17.4 22.7 2C,9

'Source: Gas Facte 1991 Data. American Qas Association, 1992.

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?13 SSO S3S5 04-21-83 08:11AM F022 113 ROE/NARUC PRESENTATION 4/27/93 CAPACITY OPTIONS FOR THE FUTURE Order No. 636 has opened up industry-wide discussions of how •veryone would like to use pipeline capacity in the future. There are three types of capacity uses that might toe considered: original (the traditional firm pipeline use); derivative; and what might be called "imaginative." This talk focuses on the last two. The following principle of pipeline transportation regulation is a backdrop to what fallows:

MONOPOLY FUNCTIONS SHOULD BE REGULATED ONLY TO THE EXTENT MONOPOLY CONTROL CAN DISTORT THE FREE MARKET

(1) Interruptifcle transportation, or IT, is usually considered to be derived from firm capacity. That is true, in the sense that IT is not widely available in tb* aainlin* at peak usage times, but only if and when firm customers are not using their booked capacity. For this reason, some pipelines are maintaining IT is not a monopoly service, and rates should not be regulated. Moreover, some maintain, capacity release will obliterate IT, so no revenue responsibility should be attached to it. Market-based IT rates are the, goal.

But, while IT may not be available on the mainline at peak, it is available in pockets all over the pipeline at all times. So it would be wrong to attribute no cost responsibility to IT, then permit the pipelines to charge and pocket monopoly rates.

An appropriate solutiont addressing both shippers* monopoly concerns and the pipelines* capacity-release concerns, would be: (a) assign mininal costs to IT; and (b) credit all but some percent of IT revenues to the firm customers * cost of service.

*,- o... This would leave the pipeline nn incentive to find all those pockets, font not to overcharge far thorn.

(3) Derivative capacity aloo includes the secondary market for capacity formerly seen in "buy-soll" and capacity brokering arrangements, and now to be seen only in Order No, 636 capacity release arrangements. The industry is viewing this released capacity as "the new commodity" — it will be bought, sold and traded (some feel) as freely as is gas itself today.

The degree to which it will truly become the new commodity depends on the degree to which standards for sharing the Information about_ capaci ty_ develop. No-one can trade in capacity until one knows it is there. No-one can trade capacity as a commodity until we have the tools to find that information fast.

Over just the past year, the industry has evolved to hourly sales, nominations and trades. To keep up, the industry must have the information available electronically. Electronic Bulletin Boards {EBBs) or, better yet, Electronic Data Interchange (EDI) must become the universal trading tool of the future. For that to occur, the industry needs mandatory standards that permit integration of pipeline EBBs across the country. Only by integrating the information on these boards can we integrate the pipelines.1

1 A footnote on integration of capacity and information: the national pipeline grid is being blocked by non-open access intrastate pipelines, particularly in the supply area. State regulatory commissions might consider requiring open-access, non- discriminatory transport on these pipelines as well. The third type of capacity could be called "imaginative11 capacity, or "paper" capacity. From the arrangements listed above, and the tariffs and terms coining out of pipeline restructuring, it begins to appear that we can divide the pipeline into not two functions (merchant and transporter) but THREE (merchant, transporter, and Paper Shuffler, or Those Who Handle Derivative and Imaginative Capacity.) The merchant is the one that actually sells the commodity, or attempts to persuade you to buy the commodity from it. The transporter moves the gas through the pipeline. Primarily performing an engineering function, transport personnel ensure the physical integrity of the steel in the ground.

And the third function?

At the end of each month, the pipeline evaluates the month's happenings and sends invoices to those that used the pipeline -- and to those that didn't use the pipeline but thought they did. For example, a customer in West Texas may believe it moved gas through three pipelines to get to a buyer in New York, but in fact its gas went to Mexico, and the gas delivered to the New York buyer came from Alabama coastal waters. The pipelines operated exchange agreements with each other, doing what gas jockeys do best — wheeling gas around with the least physical effort possible — and then just billed the West Texas customer for transport. This is part of the Paper Shuffler function — coming up with imaginative ways of moving gas.

The Paper Shuffler has lots of other functions. It adds up the remaining imbalances on all the OBAs and other transport accounts, and cashes them out at the FERC-approved price. That means that if my account shows that I shorted the pipeline, I will be billed by the pipeline as if I had purchased gas from it.

284 The Paper Shuffler will aloo track the various releases and vm- releases of capacity on the EBB, and make sure the billings ar« correct to the new capacity holder, and the correct amount of credit was allocated to the account of the capacity releaser.

Can someone not connected to the pipeline do the paper shuffling? visualize a paper gas jockey in a satellite hovering over Missouri, doing computerized monitoring, via telemetering, of the input and output of all North American pipelines. The jockey could notice the pressure dropping in one leg of a pipeline, below what it should be. (The anticipated pressure would have been calculated by the computer, based on all the nominations inserted on that pipeline's EBB that day. The nominations would have been shared, in the aggregate by leg and without identifying market'-sensitive information, with all who accessed the EBB.)

The computer jockey transmits to the EBBs of all her clients who nominated gas into that leg, notifying them that one or more of them may be short. (Better yet, the jockey's computer shows which of them is short because their wells are telemetered.) If that doesn't work, the jockey calls up emergency support supply from somewhere else on the line, and the pressure returns to acceptable limits. Then the computer drops the cost of the emergency support into an account that will be charged against whichever supplier turns up short at the end of the month.

Even if the pressure-monitoring and calling for additional supplies is performed by the transporter personnel, and not the Paper Shufflers, the Paper Shufflers get their day at the end of the month — and the information can be handled down the hall, or by an out-sourcer across the country, or even in the sky. Nominating, scheduling, imbalance monitoring, invoicing — all of this can be handled by someone other than the pipeline. And maybe better than the pipeline, because the computer jockey is handling the information on behalf of many shippers on »any pipelines, and aggregating for them.

The computer jockey can also broker, ao a commodity, capacity on many different pipelines. Visualise Gas Traffic Controllers sitting in front of 20 TV screens monitoring where segments of capacity appear on different pipelines, aggregating them into packages that workably move gas, and posting the package's for sale. Using that broker's services, a shipper can save considerably on transportation, and potentially access a low-cost package not previously thought accessible.

There are problems to be worked out here, including technical, administrative, financial and regulatory ones. For example: How are the pipelines charges equitably allocated? Heaven only knows. But if we can figure out how to fairly allocate transition costs, these problems should be a piece of cakeI

286 CAPACITY OPTIONS: INDEPENDENT POWER PRODUCERS, PIPELINE CAPACITY, AND STATE COMMISSIONS

JAMES SCHRETTER, VICE PRESIDENT C.C. PACE RESOURCES

FUEL MANAGERS ASSOCIATION

Prepared Remarks for: DOE/NARUC National Conference on Natural Gas Ur,c New Orleans, Louisiana April 26-28, 1993

C.C. PACE RESOURCES and the FUEL MANAGERS ASSOCIATION (FMA) are pleased to participate in this timely conference on natural gas issues facing the states. Bruce Ellsworth, Ken Malloy, and the NARUC and DOE staffs are to be applauded for working so diligently to successfully pull together a conference of this scope. With the imminent advent of capacity release program on the interstate pipelines, this panel's concern with new capacity options is verv timely.

C.C. Pace and FMA bring to this panel the views of the INDEPENDENT POWER INDUSTRY. Independent power producers (IPPs) are expected to be the largest new users of pipeline capacity in the r.e?:t ten years. This increased use of gas will come, we hope, from significant new investments in power plants. But there's more to the IPP potential. IPPs can help states:

• Increase employment; • Maintain or lower residential anu commercial energy costs-both electric and gas; • Increase economic development; and • Provide a cleaner environment.

THE POTENTIAL IPP MARKET

There is another panel in this conference focusing on the electric generation market; here the discussion of the potential market for gas-fired power generation briefly focuses on capacity acquisition by IPPs. This is an overview, and it should be remembered that the growth of electric generation will vary widely between states. Potential $43 Billion Investment C.C. PACE wears a number » hats in ihc nntural gas industry: fuel manager for severs! gas'fired independent power projects; independent provider of The investment potential for non- industry-grade electric dispatch analysis, gas consultant utility power generation is huge. Recent to independent power developers and financial studies have projected between roughly institutions lending lo ihe IPP market, gas contracting representative for power producers and industrials, as 35,000 and 45,000 MW of new independent well as manager of an LDC, Kentucky Ohio Gas power capacity by the year 2000. A Company. These various roles allow C.C. •Pace to look realization of 43,000 MW would equate to ai iv-u.y's issues from a variety of pcrspeciives. approximately $43 billion in investment. FMA is a trade association of entities, now numbering thirty, lhal develop, own or manage non- 75% of New IPP Capacity utili'.y electric generation projects located in North America, or that provide services to such projects, including fuel management, financing, and operations Natural gas is fast becoming the fuei and maintenance services. FMA includes a number of of choice, not only for lPPs but also for the large, it IPP developers, such is DESTEC utilities. Utility Data Institute recently ENERGY, COGENTRIX, and MISSION ENERGY. released statistics that indicate an increase of FMA is unique in that it also includes companies such AS GENERAL ELECTRIC and CREDIT SUISSE, 17% in the use of natural gas by builders of which finance independent power projt«ts. new U.S. power plants. Additionally, C.C. Pace' studies indicate that roughly 50% of FMA is faeuscd on gas-fired power generation operating IPP capacity is gas, but and has been deeply involved in the restructuring of interstate pipelines under FERC's Order 636 policies. approximately 75% of new capacity since A party to all of the proceedings and actively involved mid-1991 is gas-fired. in over twenty cases, FMA has undertaken * significant effort to obtain the tariff terms which will allow the Off-Peak Co» ttmptivn potential for gas-flrcd power generation to be achieved.

Two important fuel characteristics of new IPP power plants are volume and peak gas period requirements. Recently, the size of the typical power project has grown from 50-100 MW in 1989 to 250-350 MW in 1993. A 300 MW power plant consumes substantial volumes of gas: up to 45,000 Btu/day. This is the equivalent to three or four good sized industrial facilities. But most IPP projects do not necessarily need to use gas at the same peak periods as LDCs, which is typically a cold winter day. Otherwise, the plants have a contractual right not to run because of limited run times. If the plants must ran, an alternate fuel, such as fuel oil, can be used. If the plant is "dispatchable" or a "peaker," it may not be running at that time.

This ability to use substariial volumes of gas, but avoid LDC peak periods, makes IPPs a great match with the gas distrit ution in your state. This will addressed later in the discussion.

IPPs Face Unique financing Requirements

Unlike utilities, IPPs do not have a rate base within which to "roll-in" the cost of a new plant. The projects typically use "nonrecourse financing" under which the lender looks only at

288 the project to support the loan. Consequently, IPP projects undergo a rigorous review by financial institutions with very low tolerances for risk. This has been especially true in the last few yews. Financial institutions want a demonstration that fuel transportation capacity will be available for the loan life of the project-which is usually fifteen to twenty years. Therefore, capacity releases must meet the project time frame and recall rights cannot be mortally burdensome to financial institutions.

To summarise the IPP market:

• Independent power development in the next ten years win be large by any measure. • IPPs will be searching for large volumes of gas transportation capacity to fuel their plants. • Many 1PP projects can use aKernativc fuels during LDC peak periods. • IPPs desire to "firm up1' transportation.

A NEW ERA OF CAPACITY RELEASE

We are at the beginning of a new era of interstate pipeline capacity management using the release mechanism. This new program, a central aspect of the restructuring mandated by FERC, offers the potential for a win-win partnership between LDCs and IPPs.

Higher LDC Costs Projected, but Mitigated by Capacity Release

After the Order 636 restructuring, most LDCs under Order 636 will be paying higher demand charges as a result of the Order 636 mandated Straight Fixed Variable (SFV) rate design. Under SFV, demand charges for holding capacity will essentially include all of the pipeline's fixed costs. To the extent the LDC is always using its capacity, the impact of this change is minor. However, to the extent an LDC holds capacity it uses only during its peak periods, straight fixed variable rates can dramatically raise the LDC's costs.

FERC intends capacity release to be an important way by which an LDC can mitigate the new higher costs of holding unused capacity. For LDCs, key elements of the capacity release program include:

• Prearranged deals are encouraged; • The releasing shipper can specify the terms of the release; • Demand cost related charges can be credited to the releasing shipper's account; • The acquiring shipper can re-release the capacity, with the original releasing shipper maintaining recall rights; • The releasing shipper can segment its capacity and release portions; and • Pipelines are moving towards intraday scheduling, thereby increasing the potential for intraday releases during peak periods.

States Commissions will be Involved

State commission are charged with ensuring that local distribution companies under their jurisdiction prudently manage the capacity rights they hold on interstate pipelines. Until now, that review has mainly involved whether the LDC held the right amount of firm transportation to meet its obligation to serve.

In the near future-the very near Some example questions state future-you are going to be asked to review commissions will be asking include: more complex management of capacity. As gas users develop the market for trading • What is a prudent length of release? capacity, the LDCs under your jurisdiction • What is a reasonable discount, if any? will face a multitude of options previously • Should the LDC strike deals now, or unavailable. wait for different market conditions? • Should the LDC hold out for a There are literally thousands of customer wanting capacity year round, permutations of capacity management or release capacity now to a customer questions, and the management and priorities wanting it only during the summer? of capacity release are going to be determined • Was the LDC imprudent in rjQJ seeking at the state level. FERC is simply setting the out capacity release deals? trading forum and monitoring for undue discrimination. How the companies under your jurisdiction use capacity release is subject only to your review. Competing interests in your states will argue strongly that widely different strategies are the best course for your state's economic development, job prospects, and cost of energy.

Why not Rely on Intemtptible Crediting for Cost Mitigation ?

FERC, in its restructuring proceedings, has required pipelines to credit interruptible transportation (IT) revenues above costs back to the firm shippers. This credit is apportioned by firm entitlements. One question that arises: why should firm holders enter into capacity release arrangements when the new shipper will otherwise move its gas via IT, which will cause a credit back to firm shippers?

21M) The IPP industry, or at least FMA members, support IT revenue sharing. Many existing power projects, especially peaker units, rely on intemiptiblc transportation. FMA has argued before FERC for rate designs that ensure vigorous marketing of IT capacity. The continuation of an IT market is important, noi only for certain customer needs, but also to provide a competitive alternative to capacity release. As customers, IPPs want FT holders and pipeline IT to be in competition for our business.

From the LDC's perspective, there are distinct advantages of capacity release over interruptible transportation including:

• iJirect crediting of revenues to the LDC, rather than only a pro rat a share; • More flexibility over capacity rights through contractual control; and • Possible reduced reliance on more expensive no-notice service.

FERC has recently niled thai pipelines must guarantee IT service for 24 hour periods. Capacity release, because it provides a contractual framework for the exchange of title, may provide more flexibility because the capacity can be recalled even during the gas day.

(Note:: under the 1992 PUCHA reform state commissions are given the power to perform a prudency review of IPP fuel plans and programs. For gas-fired power projects, this can present another avenue by which state commissions can evaluate the management of pipeline capacity.)

Tlie Role of IPPs

How does this relate to IPPs? As you recall, IPPs must demonstrate the security or their fuel supply transportation for fifteen or more years. There are basically three types of capacity available: firm, released firm, and interruptible.

Since FERC began allowing transportation on interstate pipelines a little over seven years ago, many utilities, IPPs, and industrial customers have relied on interniptible transportation. This has been a fairly reliable service because FT holders-predominately LDCs-couId be relied upon to use capacity only during winter periods.

Now the reliability of IT has suffered because of the creation of reused FT. With a stroke of a pen, gas flowing via IT can now flow as firm transportation. When there is any possible constraint of pipeline capacity, gas users will be taking a risk to continue to rely on interruptible transportation. In such cases, a new customer could lake released FT capacity and have a priority over the existing interruptible customers.

Furthermore, even when the potential of pipeline constraints is limited, it can be advantageous to the LDC to offer the iratemiptible customer a cheaper rate under capacity release. This is possible because of (he direct crediting of payments to its account ai the pipeline for the released capacity.

Mainly for reliability, but also for price, IPPs and the institutions that finance projects will be interested in partnerships with LDCs through capacity release arrangements.

A Win-Win Partnership

The specifics of the partnership depend on the needs of the particular power project and LDC, but the foundation of the partnership is constant: the potential for a win-win situation.

IPPs and LDCs are ideally situated to find that win-win partnership. First, the ga» requirement profile of the typical LDC meshes nicely with the typical dispatchable power plant. Even a power plant that is dispatched during peak gas periods can mesh with the LDC's need^ by switching to an alternative fuel or using contractual rights to decline to run.

The specifics of the capacity partnership ;an take any number of forms. Generally, people address the LDC as the primary capacity holder. But even this need not be. For an IPP that is running most of the lime, the IPP might release its capacity to the LDC at peak periods and urn on an alternative fuel. The IPP would be, essentially, a peak shaving facility for the LDC.

Moreover, while this panel is focusing on capacity acquisition, the LDC-IPP partnership can encompass much more than capacity sharing. With their large loads and short dispatch times, gas-fired IPPs will be looking for tools to avoid pipeline scheduling and balancing penalties. Also, again depending upon the specifics, IPPs will be looking for extra gas supplies to cover peak dispatch periods. LDCs are ideally situated to provide these services.

LDC's can win by:

• Lowering the cost of holding capacity for its customers by the direct crediting of capacity release payments; • Enhancing its service integrity by sharing gas supply arrangements with the IPP; • Increasing its marginal revenue by providing scheduling and balancing services to the IPP; and • Demonstrating to the PSC that it is doing all it can to lower its costs, enhance its service, and promote economic growth.

£•> \> »«r The IPP can win by:

• Obtaining firm capacity; • Enhancing gas supply security; • Avoiding pipeline scheduling and balancing penalties; and • Enhancing overall fuel economics.

Some Difficult Areas

So far, the benefits of capacity release have been discussed. However, for state commissions, a few negative aspects should be addressed.

First, state commissions are going to be faced with arguments from current gas users, such as industrials, who have been using interruptible transportation. Industrials prefer IT because it has been a reliable service without requiring long term commitments. Power plants can commit to capacity for fifteen to twenty years, whereas many industrials shy away from commitments for more than five years. In some cases, disputes for LDC-held capacity could occur. These could present state commissions with difficult choices between the desires of existing enterprises, minimizing costs for residential customers, and the economic and environmental benefits of new power development.

Second, in sor.e cases, state commissions will be presented with a capacity release arrangement for a power plant in a different state, perhaps some distance away. This situation could arise because it is possible for the LDC to sell a segment of its capacity to a facility with upstream receipt points. For example, a New England holder of firm capacity on Transco could sell the capacity to a power plant in the South.

Recently, some states indicated concern that capacity into their stale could be used for facilities outside of their jurisdiction. This has included discussion of keeping capacity into a state restricted to users in that state. From an IPP perspective, this notion is a mistake. Free trading of capacity between states, where market demand exists is, on the whole, a win-win arrangement. Capacity costs are mitigated, whereas this would not otherwise occur, and capacity is utilized where it is needed, with resulting overall economic benefits. Also, stales should not forget that capacity release can increase the capacity available to their state, and not necessarily reduce it.

NEW CAPACITY: STATES MUST GET INVOLVED

Of course, its going to take more than an enhanced use of pipelines through the capacity release mechanism to achieve the IPP potential for economic growth and environmental benefits.

293 8 New pipeline construction is also required. This issue relates to the old question of how to price new capacity, whether through rolled-in or incremental rate designs,

Obviously, as new customers IPPs are interested in lowering the cost of new capacity. All new customers want fully rolled-in treatment, and desire the support of state commissions for ro!!ed-in pricing. However, we are fully awars that the state commissions must balance the conflicting desires and needs for a whole host of constituents, some of whom oppose rolling-in any costs of pipeline expansions. This is often a very contentious issue, and it would be inappropriate to spend this panel's time attempting to persuade you to utilize rolled-in rates.

As representatives of the growth market, C.C. Pace and FMA do have a message we would like to convey today: without state commission Lvolvement on this issue, the broad social benefits of pipeline expansions will be undervalued. This will diminish the realization of potential economic and environmental progress.

FERC's Detrimental Current Policy

In the past, FERC had a preference in f?vor or rolled-in rate treatment. However, in September, 1991, in Order 555, FERC mandated a stiff challenge to anyone seeking rolled-in treatment, completely reversing the former policy. Now the pipeline seeking rolled-in treatment nas to show that rolled-in treatment would provide overall benefits for existing customers commensurate with the increase in rates.

Order 555 imposed a number of other significant burdens on pipeline construction, including a difficult "at risk" standard. The result was that it was attacked from all quarters of the irdustry, and its implementation was stayed by FERC. Now, while reconsideration of Order 555 has been delayed by Order 636, the Order 555 principles are essentially in place at FERC.

In February, 1993, FERC issued its long-awaited rehearing concerning rates for the Great Lakes expansion project. In denying rolled-in rate treatment, FERC flatly stated:

Unless rolling-in new facility costs lowers rates to existing shippers, all new facilities should be priced incrementally.

While there are many issues surrounding the Great Lakes case, the focus of today is that the order is essentially bare of any consideration of the social benefits of gas-fired power generation.

17ie FERC Process Undervalues Broad Social Benefits

While, as former Chairman Allday stated, FERC's "pricing policy is-to put it somewhat charitably-still evolving," the question remains as to who represents the broad social benefits that acenje due to increased gas-fired power generation made possible by pipeline expansions. The U.S. Department of Energy is certainly to be commended for commenting at FERC on the broad benefits. FERC, however, does not have a clear mandate to consider these benefits. 9 Unfortunately for the country as a whole, FERC focuses its review on the impact of expansions on ^dsUngj^ijjtomeis. Thus, the Federal agency charged with deciding specific cases does not iuelf adequately value the broad social benefits of increased gas use for electric generation.

Meanwhile, LDCs and other current customers are under no obligation to consider anything other thap ;.\e cost impact of pipeline expansions. In fact, LDCs have an obligation to fight to keep the rates of their current customers as low as possible. The result is at times a chorus of voices at FERC fighting any potential rate increase involving new customers.

State Commissions Have the Opportunity to Consider Broad Benefits

C.C. Pace and FMA would like to suggest to the state commissions that you have a unique opportunity to comment on the economic and environmental benefits that can accrue as a result of pipeline expansions. Although these benefits are felt by existing gas customers, they are not adequately represented before FERC, and therefore are not adequately factored into the balancing of rate rulings.

State commissions can fill this rcle, We in the IPP industry are not asking today that state commissions flatly assume that full rolled-in rate treatment is appropriate. What we ask is that state commissions evaluate the overall economic and environmental benefits to their region, together with the overall impoct on current gas users under their jurisdiction. We are confident that the result of that analysis might, in most cas>«s, be recommendation for either full or partial rolled-in treatment.

Bringing the unique state commission perspective to this issue at FERC would not only benefit the individual states represented, but the nation as a whole.

STATE COMMISSIONS CAN HELP IPP USE OF GAS

In summary, state commissions can assist IPPs obtain the pipeline capacity needed to maximize benefits by:

• Promoting use of capacity release agreements; • Urging FERC to allow maximum flexibility of firm shippers to use their capacity; • Pressing FERC to consider the broader economic and environmental benefits resulting form increased use of gas, especially for power generation, when analyEing incremental/rolled-in expansion cases. www W r r DOE/NARUC NATIONAL CONFERENCE ON NATURAL GAS USE

CAPACITY OPTIONS

t.i INDEPENDENT POWER PRODUCERS, PIPELINE CAPACITY, AND STATE COMMISSIONS

C.C. Pmcm naiouwi, fne. AIM www FUEL MANAGERS ASSOCIATION

Trade Association for Gas-Fired Cogeneration and independent Power Accounts for 70% of AN Gas-Fired Projects Developed in the U.S. Established to Act as Regulatory Advocate for Members on Key Fuel-Related Issues

C.C. Pacm RMouraN, Inc. MMM www,GROWTH IN NATURAL GAS CONSUMPTION 1992-2000

1060 7£%

38%

18OO to e ID S "400 13% 9% 200 3%

Non-tflHRy UtMy LI CMTAI UliUTTMirAlMmiflE c.c. JJJ www OUTLOOK

HIGHER LOCAL DISTRIBUTION COSTS ARE PROJECTED

Inc. www MITIGATION

HIGHER LOCAL DISTRIBUTION COSTS ARE PROJECTED

CAPACITY RELEASE CAN MITIGATE ADDITIONAL EXPENSE

NIC MIA ^ ^ ^ KEY ELEMENTS OF FERC CAPACITY RELEASE

Prearranged Deals

Releasing Shipper Specifies the Terms

Demand Charges are Credited Back to Releasing Shipper

Re-Released Capacity

Intra-Day Releases may be Possible

C,C, Pact n§Bounm§, Inc. JJJ www SAMPLE STATE CONCERNS

Prudent Release - Length - Discount - Time of Year - Recall Rights

Grant Today or Hold-Out

Imprudent LDC Behavior

C.C. P*c# RMOUI£^, Inc. AIM www WIN-WIN PARTNERSHIP

BENEFITS LDC IPP Mitigation of Ability to Underutilized Capacity Obtain Capacity Enhanced Service Possible Avoidance Integrity of Penalties Increased Marginal Enhanced Economics and Revenue Gas Supply Security Encouraging Economic Growth C.C. Pac« RmoutcM, Inc. MMM WWW r r r NEW CAPACITY ROLLED-IN VERSUS INCREMENTAL RATES

Currant FERC Rules Impose a Stiff, All-or-Nothing Burden Against Rolled-ln Treatment FERC Is Not Adequately Mandated to Consider the Broad Economic and Environmental Benefits of CO Pipeline Expansions LDCs and Other Current Customers are Likewise Not Charged to Consider Broad Social Benefits The Result: Under-Assessment of Broad Benefits and Harm to Economic and Environmental Progress

CO. Pitt RMOOTCAC, Inc. MMJk www r w F NEW CAPACITY STATE COMMISSION ROLE

state Commissions Have a Unique Opportunity to Consider the Broad Social Benefits Accruing due to Pipeline Expansions

State Commissions Must Take a Central Role in Debates about the Pricing of New Capacity

C.C. Pact* RmMMirc**, Inc. AMI www ASSISTANCE IPPs SEEK FROM THE STATES

Long-Term Capacity Releases of LDC Space Viable Recall Rights for Consumers, Developers, Financial Institutions and LDCs Prudent LDC Rates and IPP Cost Pass-Throughs When Warranted

C.C. Pwem RMourcM, Inc. MMM www HOW STATE COMMISSIONS CAN HELP

Promote Capacity Release Arrangements (e.g., Consider State Bulletin Boards for Long-Term Releases) Approve Recall Rights Acceptable to Multiple Parties

*••* Urge FERC to Allow Firm Shippers Maximum ••-* Flexibility Establish Prudent LDC Rates Consider Broader Economic issues in Rolled-ln/ Incremental Expansions

C.C P#c# ftosourcM, Inc. www ULTIMATE BENEFITS

Increased Employment

Existing or Lower Residential and Commercial Costs

Increased Economic Development

Cleaner Environment

C.C. Pac« RMOuroM, Inc. 1AM INCENTIVE RATEMAKING

An LDC Prepares

for the Year

G'dCi Service A Western liesvurces Company TRADEMARKS OF THE NINETIES

Competition

Change Customer Interests Innovation and Technology

Service A Western Pxsources Company

310 CUSTOMERS

Demographics

Attitudes

Values

Service A Western Pjsourcts Company

211 CUSTOMER SERVICE

Options

Choices

Affordable, Dependable, Reliable

Gas Service A Wattm rjtouras Cowywy

3.12 INGREDIENTS TO LDC SUCCESS

Change Oriented Innovation Customer Driven

Flexibility Employee Emphasis Financial Strength

Gas ServServic. e A Water* Pjttourm Company ROLE OF INCENTIVE RATEMAKING

Protect the Consumer Encourage Innovation Flexibility Enhance Competition Improve Service Allow Financial Strength

Service A Wtstem Emmas CmjMmy

311 INCENTIVES

JJerServicv e YhOtrn f'ssourm Company

o '."» GAS SUPPLY TARGET

Target Price

Share Benefits PGA Review

Gao O&M INDEXING

Manpower

Technology Innovation

Service A Western Pxsouras Company

31? CONTINUING SURVEILLANCE PROGRAM

Performance Driven

System Safety Plan

Flexibility

Service A W:st*m PxsouTas Company CONSTRUCTION INDEX

Main Replacement Service Line Replacement

Cathodic Protection

Service A Y/nttnt Pjttottrm Oomftmy CUSTOMER SERVICE ITEMS

Abandoned Call Rate Average Wait Time Collection Activity Complaints Leak Response Time

Service A Western Ilaounes Company

32® WEATHER ADTUSTMENT CLAUSE

Stability of Revenue Predictability Enhanced Planning

Gao Gerv A Wssftm jResc-ircfS Company INTEGRATED RESOURCE PLANNING

Reward Supply/Market Planning Environmental Initiatives Promote New Technology

Service A. Wsstem I'esmmes Company

•2! FINANCIAL TARGETS

Cost of Capital Credit Rating

Service A Western I'xsvurcts Company DIVERSIFICATION PLAN

Trading Appliance Repair HVAC NGV Cogeneration

Service A Western I'ssaurtts Company RATE DESIGN

Contract Demand Gas Measurement Load Factor Based Rates Tailored Rate Design

Service A Western Pxswrces Company THE RESULTS OF INCENTIVES

GcL'J Set Wee A Western resources Company 32S A BASKET OF OPTIONS

Flexibility Innovation Service Financial Strength Annual Review

Service A Western lUsuums Company

327 RATE CASE ACTIVITY

Limited Trade Off Exception Provision

Gas ServicServ e A Western Resources Company BENEFITS

Protect Consumer Encourage Competition Enhance Innovation/Technology Options/Choices/Service Flexibility Financial Risk and Reward

GclG Service A Western Resources Company REMARKS OF PAUL R. ZIELINSKI, DIRECTOR OF CORPORATE PLANNING AND REGULATORY POLICY, ROCHESTER TELEPHONE CORPORATION at the NARUC-DOE National Conference on Natural Gas Use April 27,1993 in New Orleans, Louisiana

I. Introduction

For the past six years, Rochester Tel has been operating under some form of incentive regulation. Our experience suggests that the basic goals of incentive regulation are achievable. It does end the cost-plus mentality of traditional rate- of-return regulation; rewards efficiency; encourages appropriate investing; and permits ratepayers to share in the benefits the new incentives create. As a next step we have proposed the establishment of an even more dramatic competitive regulatory scheme that I'll describe briefly at the end of my comments. However, first Td like to discuss the major provisions of our Incentive Plan and the rationale behind it.

II. Incentive Regulation Plan

Our current incentive regulation initiative became effective in 1990. We were coming off a successful rate moratorium agreement and neither we nor the Commission were interested in returning to traditional rate-of-return regulation again. The rate moratorium had provided incentives for us to become more efficient, and we believed that the momentum we built up had to be continued. We were not eager to go back to continual rate cases. They produce delay, uncertainty, tremendous expense and create an adversarial relationship with regulators. We felt we had turned the corner and put all of that behind us with our rate moratorium agreement. We wanted to continue to move forward.

By the end of 1989, our local market was becoming very competitive for several services. Rochester, New York is home to Eastman Kodak, Xerox and Bausch & Lomb-large, sophisticated customers who have alternatives to our local network. As technology advanced, it became increasingly important that we kept up and continued to be the best value for our customers' communications dollars. The constraints of traditional rate-of-ref urn regulation made that objective increasingly difficult. We needed more ability to respond than was possible under the older form of regulation. Consequently, we developed-along with the NYPSC staff-our Incentive Regulation Plan-the first of its kind.

Under our Incentive Regulation Plan, two service categories were created: monopoly services and other services. Monopoly services represent basic access fine service; the "other" category covered competitive services like Centrex and discretionary services like Call Waiting. The pian was to last for three years. Monopoly services were allowed to increase on January 1 of each year by the inflation rate, less a 3.25% productivity offset, plus or minus any regulatory, legislative or accounting cost changes outside of our control.

Pricing flexibility for competitive offerings was an essential part of the plan to us. We were permitted to increase or decrease rates for competitive services up to 25% of current rates. Discretionary services were permitted a much greater range. That pricing flexibility was coupled with the ability to change rates on one day's notice instead of having to wait the normal three month filing time previously in effect. Flexible pricing enabled the company to act more like a competitive company and encouraged network investment.

An 11.7% return on equity was used to set initial rates, then was adjusted to reflect changes in interest rates each year. It was also used as a basis for sharing earnings with ratepayers: the first 50 basis points were returned to ratepayers; the company kept the next 50 basis points; and anything above 100 basis points was divided evenly between ratepayers and the company. This sharing arrangement alleviated much of the regulators' concerns with discretionary expenditures and capital investments while incenting the company to act in a business-like manner to increase earnings.

Service quality was another important part of our plan. We agreed to stringent quality standards significantly higher than those required under then- current regulations. Failure to meet those new standards would result in a refund to customers of one-half of one percent of monthly monopoly service revenues- about $600,000. This financial commitment provided regulators assurance that we weren't cutting expenses and investing in ways which might impair service quality. Needless to say, no refunds were required.

Finally, we received permission to exclude certain discretionary services such as Call ID from the sharing rate-of-return calculations for four years in exchange for assuming all the risks of investing and marketing them. We believed it important to separate ratepayers from company funding of discretionary services.

Our incentive regulation plan has been a positive experience. Everyone was better off as the advantages of incentive regulation took root. Customers received rate stability-even reduced rates in real terms. They got a lower cost structure on which future rates would be based and they got new services faster. Last but not least, customers became entitled to almost $1.5 million in shared earnings.

The company was also able to retain a corresponding amount over the three year period. In addition, the company was compelled to end its "cost-plus" thinking. Incentive regulation forced us to reassess investments and expense control, and the multi-year nature of the arrangement eliminated any expectation that we could readily return to the rate-of-return well. No longer could we make investments on the "hope" that revenues would materialize to cover costs or on the expectation that ratepayers would cover them. When the company makes investments today, we have a clear understanding about the targeted markets and returns expected. As a result, our cost structure is moving towards that of our competitors. We intend to be tough competitors, and the incentives we've been operating under have positioned us well.

Our Incentive Regulation Plan was innovative and appropriate for its time. Without that experience, it's unlikely we would have proposed our Open Market Plan, which we believe is the next logical step in the transition to a fully competitive environment.

III. Open Market Plan ,i - ' Competition has intensified over the past three years. Advancing technology and regulation are forcing our local markets open and encouraging new competitors. Wireless services, such as cellular and Personal Communications Service, and cable television links are obviously direct competitors for basic local telephone service in the near future. Simply controlling expenses won't be sufficient to survive. We are seeing more substitutes for all of our services and increasing competition. We've concluded that more dramatic and fundamental structural and regulatory changes are necessary to compete effectively. Our Open Market Plan, which we filed with the NYPSC in February, creates a new wholesale telephone company and new retail telephone company out of the local telephone company operations in Rochester and opens the entire service territory to competition for every customer-business and residential.

The new wholesale network company, which we ar9 currently calling R- Net, retains the monopoly functions of the public switched telephone network and will offer unbundled services at tariffed prices to all retail providers of telephone service on a non-discriminatory basis.

The new retail competitive company, which we are currently calling R- Com, will sell competitive and discretionary services, by reselling services purchased from R-Net or others and by adding its own software and value.

We see our Open Market Plan as a logical extension of our Incentive Regulation Plan. Presently the company takes sole responsibility for just a limited set of competitive and discretionary services (e.g., voice mail, advanced custom calling features). Investments and expenses required to provide those specific services are not included in our revenue requirement, thereby relieving ratepayers of the costs and risks of new service development. That concept has been expanded in the Open Market Plan to include all competitive services- existing and new, which will be provided by our competitive retail subsidiary R- Com. Ratepayers will no longer be asked to underwrite the expense of any competitive or non-essential services. And offering such services through a new structurally separated subsidiary eliminates potential problems with cross- subsidization and ends the need for elaborate cost allocation schemes.

332 On the remaining monopoly side, regulated offerings from R-Net will be subject to price regulation following an initial rate setting investigation. Price regulation continues the rate stability of our Incentive Regulation Plan and avoids the disincentives of rate-of-return regulation. To insure the most efficient and high quality network, R-Net must have the proper incentives to continue to reduce expenses and also make timely and judicious investments. Incentive regulation was designed to make companies which were essentially monopolies act more like competitive companies. Our Open Market Plan creates a fully competitive environment. Price regulation, without earnings sharing, better parallels the realities of the competitive world and encourages even more cost cutting and strategic investing.

We recognize that our local market is not yet fully competitive and that regulation is still appropriate for our monopoly functions. By unbundling as much of our network as feasible and tariffing discrete monopoly functions and making them available through a separate subsidiary on a non-discriminatory basis, we are ensuring thai there will be minimal regulatory distortion in the Rochester marketplace. That, coupled with our lightly regulated competitive subsidiary, will permit Rochester Tel to compete, as unfettered as possible, in a marketplace still in transition to competition. It also insures that our competitors and our customers are protected.

In our view, regulated telephone companies facing competition must be accorded the same freedoms that competitors enjoy, particularly with regard to pricing, investing and freedom from special burdens. We are not requesting special privileges or special protections while espousing competition. By structurally separating our monopoly and competitive operations and encouraging competitive entry into the very heart of our business, we have backed our vision with unambiguous action. We think it important to continue to move towards an environment where competition will thrive, where innovation will flourish and basic services at affordable rates will be available to all.

IV. Conclusion

Our Incentive Regulation Plan was appropriate for its time and worked well. We believe our Open Market Plan builds on that strong foundation and will prove even more beneficial to all involved as we evolve to a fully competitive market for telecommunications services. 4/28/93—as delivered/for reprint

"WORKING TOGETHER IS WORKING FOR NATURAL Remarks by Richard D. Farman Chairman Natural Gas Council Chairman and CEO Southern California Gas Company DOE/NARUC National Conference on Natural Gas Use April 27, 1993 New Orleans, LA

I. INTRODUCTION

Good afternoon!

And thank you, Commissioner Bailey, for that kind introduction.

I very much appreciate the opportunity to be with all of you today. You constitute an important cross-section of government and industry policymakers impacting the natural gas industry, and we are gathering at a particularly dynamic time.

The natural gas industry is coming together as never before. First, as this conference illustrates, federal and state government policymakers are committed to finding common ground on the restructuring of natural gas. Second, we all increasingly recognize that energy and environmental issues are merging. And, equally important, that they offer the hope of providing future economic growth at both the national and state levels. So we—all of us in this room—should be working together to find the optimum

0.5 4 balance among the "three Es"—energy, the environment and our economy.

Today. I would like to offer you my perspective on what the industry is doing in this regard and how these effoits relate to your responsibilities as regulators. I will start by giving you general background on the Natural Gas Council, a relatively new industry entity that I have the pleasure of chairing. Then, I would like to touch on the shift in emphasis from the federal to the state level in the natural gas industry; and finally, I would like to leave you with a few persona! thoughts about what my state, California, Is doing to recognize the market realities of the 1990s.

First, what is the Natural Gas Council? Why was It formed? What does it do, or try to do?

II. THE NATURAL GAS COUNCJL

The formation of the Gas Council was a response to a hard, cold fact that in a time of increased environmental sensitivity, our nation's cleanest fossil fuel was playing less of a role, relatively, in the national energy mix than it had 20 years earlier. Natural gas went from providing about one-third of the nation's total energy consumption in the 1970s to providing about one-quarter of that energy earlier in the 1990s. And within the gas industry, there was very little agreement on major ways to reverse this situation.

It was clear to major gas industry leaders from all segments that we needed to create new ways to work together toward the common goal of allowing our fuel to achieve Its rightful role in the nation's energy and environmental mix. The Coundl does this by bringing together four major trade groups—American Gas Association, Interstate Natural Gas Association of America, Natural Gas Supply Association and the Independent Petroleum Association of America. In addition, there is substantial marketer participation and added representation from Canada through the Canadian Gas Association and the Canadian Association of Petroleum Producers.

The Gas Council includes about two dozen top executives from these industry segments. In its 18 months of existence, we have demonstrated that we can work together...that we can stimulate demand for natural gas...and that we can improve the public perception of our fuel.

Among the Council's major initiatives which I think would be of interest to you today are (1) efforts to address the long-term reliability of natural gas, (2) efforts to reduce the impediments to the increased use of natural gas in the production of electricity and (3) cooperative efforts to help pave the way for the full restructuring of the industry in the post-Order 636 world.

As a brief aside, I might mention that the passage last year of the National Energy Policy Act and the Clinton Administration's 'avorabie recognition of natural gas both suggest that the timing is right for the industry to come together as a cohesive force.

3'M) Parenthetically, I might add that the industry Is working as a cohesive force on the problems we perceive with the Clinton Administration Is proposed energy or BTU tax, a subject covered in an earlier panel discussion. However, I am pleased by President Clinton's Earth Day announcement last week concerning the mandating of increased use of alternative fuel vehicles in federal fleets, i think this gives natural gas a chance to increase its role as a clean fuel alternative in transportation. It was encouraging that Gary Mauro, a strong advocate for natural gas as the Texas Land Commissioner, was named to head the Federal Fleet Conversion Task Force reporting to DOE Secretary OLeary. The Natural Gas Council and I, personally, stand ready to help Gary and the Administration fulfill the vision of creating a clean fuel fleet for the federal government.

III. RELIABILITY TASK FORCE

Turning now to the three Gas Council initiatives I mentioned, our approach is to involve top leaders from all of the major industry segments. The reliability issue is a perfect example. The Reliability Task Force is headed by Dave Biegler, Chairman/CEO of ENSEARCH. Dave's subgroups—each headed by a leader from a different industry segment— are actively addressing four specific objectives:

1. To define and help implement joint industry/government actions to improve natural gas reliability. 2. To plan contingency operations and communications to respond to any temporary reliability problems.

3. To help create uniform Industry communications and data availability to avoid future reliability problems.

4. To help provide timely publication of Industry activities addressing reliability and giving customers better information to meet their needs.

As part of the reliability issue, the Gas Council wants to make sure that as the industry changes that we have the right measurements of reliability. It may well be that In todays re-structured Industry, with new competitive practices and new technologies, the traditional ways of looking at drilling rig counts, storage levels and pipeline capacity utilization needs to be re-examined The Natural Gas Supply Association's recently released report on deliverabiiity and AGA's report on exploration may shed other, valuable light on these issues.

Another initiative related to reliability and the post-636 restrycturiog drew a lot of discussion at !ast weeks meeting of the Natural Gas Council—Electronic Bulletin Boards, or "EBBs."

IV. ELECTRONIC BULLETIN BOARDS

In my judgment, Electronic Bulletin Boards Is an excellent, real world example of where the Gas Council can add value. Prior to the creation of the Council, there was an Industry vacuum surrounding issues like this one. This Issue Is one In which the three main segments of the Industry have varying levels of responsibility and expectations, as you probably know. Each has different "needs" and "wants".

So, the Gas Council is attempting to "balance the interests" to find common solutions that ultimately help our customers. Through a separately established task force, the Council Is monitoring developments, looking for areas of disagreement in which it can be helpful, and finally, providing a customer perspective wherever possible. WeVe learning a lot as we move along.

For example, we have learned that there needs to be more engagement and interaction at the pollcymaking level. This is true because most of the disagreement is focused at the technical level, on issues such as proprietary aspirations, and the senior level represented by Gas Council members hopefully can raise the discussion to broader policy concerns.

But this is an incredibly complex subject. Nevertheless, 1 am confident that the Gas Council can contribute something of value to the July FERC staff recommendation scheduled under the post- 636 implementation plans. FERC has five working groups addressing the electronic bulletin board issue. The Gas Council has a task force headed by producer and pipeline leaders working to provide useful input to the FERC groups. This is consistent with FERC's determination to get ail relevant parties to provide input. Hopefully, the Gas Council, as I said earlier, can help balance the interests of industry segments and their varying customers' needs, and help bring about a smooth transition to a post-636 operating environment.

V. ELECTRIC GENERATION

The Gas Council's third initiative I wanted to mention is the effort to reduce the impediments to increased use of natural gas for electric generation. Various reputable studies of late are calling for this effort. The Gas Councils main activity here has been to develop and enhance a dialog with the Utility Electric Generation customers. Past efforts to start such dialogs were not continuous. This latest effort 1st

The process is unfolding on a regional basis to recognize the marked differences from one geographical area to another. Discussions between natural gas executives—producers, pipelines, distributors and marketers—and electric utility executives have begun at the policymaking level. And they will continue on the technical, operating level where they must become an ongoing part of our respective businesses.

After an initial pilot regional meeting In New Jersey last fall, the task force developed a formal presentation aimed at UEG Industry leaders. The presentation was "tested" on an audience from the Edison Electric Institute, and we received some candid feedback on what worked and what didnt.

With the help of that presentation and a cross-section of senior people from both industries, successful meetings were held last 8

month and earlier this month in Atlanta, Georgia, and Columbus, Ohio. We have learned, among other things, the Important role long-term contracts can play In Increasing natural gas1 role in the UEG marketplace.

The task force is looking at the Pacific Northwest (Washington and Oregon) for the next policymaker dialog. Ultimately, In all of these regions truly two-way dialog is a necessity.

To summarize the status of the Gas Council—last year we tried to bring to life the theme of "Working Together." This year, informally that thrust has evolved Into something like: "Working Together is Working." The thre? initiatives I have cited as examples are living proof that it works, and we plan to do more of it.

VI. FOCUS SHIFTS TO STATES

The activities of the Natural Gas Council also recognize the increasingly important role the states will play In the future of natural gas. i am sure most of you readily recognize this fact as well, since the state perspective is represented by the majority of the people at this conference. So, let me spend a few minutes on this subject. And so that there are no surprises, let me say at the outset that, in my judgment, states need to aggressively accept responsibility for establishing a healthy framework for natural gas if we are going to provide the public the benefits envisioned for this environmentally desirable and secure source of energy. As you know, in the 1980s, the natural gas Industry was focused for the most part on Washington, D.C., and the series of FERC actions leading to the gas industry restructuring. The post-Order 636 environment gives the states an increasingly important role In determining the impact of energy/environmental policy. This means, in part, looking at new regulatory structures for the largest customers for natural gas—UEGs and industrial users. A "business-as-usual" approach by the state regulators and energy policymakers will not work. New approaches are called for.

Support for this approach is found in a major national study that was completed last year. I am referring to the natural gas study by the National Petroleum Council. It represents a strong consensus among the natural gas industry, academia, government and the Petroleum Council. It points to a 60-year supply of domestic natural gas using present consumption rates. The study also makes clear that we, as a nation, must address the questions of reliability, pricing and ultimately the need for new regulatory approaches at the state level.

In a chapter of the study devoted to regulation, regulators are encouraged—quote—"to allow competitive market forces to continue to develop and work"—end quote.

Within this context, the NPC study includes specific recommendations for state regulators. Four of those recommendations can be described briefly as follows: 10

1. Regulatory objectives should result from coordinated state/federal agreement on a new definition of "public interest."

2. "Public interest" should be defined in terms of a functional, competitive gas industry that provides a range of products and services. It should not be looked at in traditional monolithic, monopolisitc terms.

3. Regulators should work with both gas Industry participants and consumers to develop the new regulatory structure consistent with the new "public interest" goals.

4. Ultimately, regulation should help foster—not restrict— choices for buyers and sellers of energy services.

In my judgment, it is time to take seriously recommendations such as those offered in the NPC study. For me, those recommendations signify the importance of three elements needed in the natural gas business: market-incentives, flexibility and customer-focus.

Market-based incentives are needed in place of command- and-control regulatory approaches. Flexibility is needed on the part of both regulators and utility companies. The phrase "regulated competition"—that is the use of traditional regulatory practices in contestable markets after the introduction of competitive forces—can only be described, in good conscience, as an oxymoron. Customers should be the common focus. At the risk of 11

sounding trite, the overriding need Is to add value for the customer. The customer must be looked at Increasingly In more finely divided segments that are Inter-related, but with their own separate needs.

VII. SOCALGAS EXPERIENCE

Fortunately, I feel the present California Public Utilities Commission is open to new ideas and approaches that incorporate these elements. The current commissioners recognize that we are operating in a whole new arena. This was made abundantly clear this past week—not In the context of regulatory reform of the natural gas industry, rather with regard to the potential reform of the "electric services" Industry. But the issues are similar.

I believe California should, and the Commissioners are prepared to, take a truly comprehensive, strategic look at regulatory reform rather than dealing with these issues through the normal "venetian-biind" perspective of narrow, adversarial proceedings. Based upon our experience of regulatory reform of the natural gas industry, I believe that we must all be prepared for a long, painful regulatory process at the state level.

Why? As we all know, change is always difficult. It takes time and requires, first of all, that all the interested participants must recognize and accept the need for structural charge. In addition, regulatory reform and the introduction of competitive forces involves a continuing conflict or tension with traditional regulation.

344 And this tension requires a fundamental re-examlnatlon of the existing regulatory compact.

Moreover, in these types of restructuring, all of the critical parties- customers, shareholders, regulators, employees, legislators and others—have become skilled participants in the art of watering down the process of reform.

Despite these difficulties, I believe regulatory reform of the natural gas industry needs to move ahead rapidly at the state level and can best be handled in broadly-based, strategically-oriented regulatory proceedings that focus on the customer and search for the common interest of all parties.

Therefore, I—for one—see hopeful signs in California and elsewhere for natural gas at the state level. Maybe that Is a good place to stop and move onto my concluding comments.

VIII. CONCLUDING REMARKS

In conclusion, let me leave you with three points that have emerged for me as a natural gas industry leader. They are:

1. We must all face up to market realities.

2. We must begin, working together, to write a new history for natural gas.

3. And to do this, you must build more federal-state alliances. To underscore the first point let me simply say that there Is a certain inevitability of choice In contestable markets.

My second point offers a means of recognizing these market realities by closing the book on our history of over-reliance on regulation. And by starting to write a new history. One that replaces a government-focus with a customer-focus. One in which each segment of the gas industry—LDCs, pipelines, producers, marketers and brokers—listens to its customers, and the regulators facilitate this "listening."

The third point—alliance-building—grows out of the National Petroleum Council study, which is critical of the lack of coordination between federal and state regulators. The result is confused consumers at a time when the nation is policymakers are expecting greater consumer interest in natural gas.

As a final thought on the federal-state alliance building, I would suggest that you consider taking more advantage of what the DOE has learned over the past 5 or 10 years. You can use that information in striving to make the restructuring of natural gas timely and effective. In my judgment, DOE should proactively provide some "clearinghouse" functions for helping states make sure that plans and reality match up from state to state. By working together, you can provide the flexibility that the ultimate energy providers—the LDCs and marketers—need to effectively serve our customers'interests.

34fi 14

As I said before, I am hopeful about the future of our Industry, In part because of conferences such as this one. 1 think we can get the job done. But if will take the cooperative efforts of all of the varying interests represented at this conference. I look forward to working with you to make it happen.

Thank you.

O « '1 34 i tf I *lt 466 8838 BI1J. SUM t»t

BILL SHANE'S BULLETS y ttto BTU t*x

1. Public utilities are the tax collector par excellence, they've bad a lot of practice, so n would be administratively easy to hove the pipes collect the OTU Uix frvm LPCtf at Use City Gule MfcUyrliig SluUuu and from mdusuiea at the plant gate. OB April 1. 1993. the office of Tax Polity proponed to impose the BTU tax on the LDC or industrial end user upon delivery from the pipe, with collection by the pipe. Utilities would DC denied certain taw benefits for periods during which the energy tax IB not com- pletely passed through to end users. Although State Commissions will, no doubt, strongly criticize this proposed coercive feature of BTU tax 100% paaa through. I submll Uic icasona for complete passturowgh arc persuasive evea If this coercive feature is removed when rhr BTO tax becomes law. 2. There should be 100% pass through to customers of the BTU tax by State Public Utility Commissions based on the take or pay experience. 4? oi 50 State PUC'S did a 100% passthrough of take or pay costs when the reasons were less compelling, with the BTU tax there is nobody to blame within regulatory reach. Furthermore, an >«]uitahle sharing" rationale applied to a BTU tax would stub its toe on Galveston Electric Company v. Galveston. 258 U.S. 388-50011922) and It progeny. 3. When the Tax Reform Act of 1986 reduced the Corporate Net Income Tax from $8% to 36%, State commissions were quick to pass that rcducUun inrough to customers wlUroul a full-blown rate case. Why ia it different when the tax goes up? 4. How do you make a utility more efficient by disallowing 100% pas- sthrough of a Federal Tax? If you think uymties ore now over earning, then start a rate reduction proceeding now and don't wait a year or two for the BTU tax. Just as utilities are damaged by regulatory lag when the CDSt Of capital goes up, things get balanced M Uiey can benefit from regulatory lag. when the cost of capital goes dawn and thfty can re- finance.

R-34S ] 412 «65 S83S 04-05-93 0*:07PM P002 013 X 412 485 MM BSIX SfltVKR

3. I sympathize with me NARUC Resolution tbat states tltat a BTU tax "not restrict f-cgulatury commiRSioiivS discretion Jn the treatment of costs associated with the imposition of energy taxes". When the Congress passed TKA '86 reducing the CN1 from 48% to 36%, past tax ivarmallzn* don at the higher rate was not flowed through to customers m the now- defunct Dorgan Bill proposed. Given (lilts bitter experience, I under- stand why commissioners oppose Federal Tax mandates. 6. Does anybody uaik think a BTU tax can be "relatively invisible"? Imag- ine the articles and eventually bill Inserts In coming months. Rational candor suggnatn putting the BTU tax ab a lino Hem on the customers utility hill just as is now done with the subsenncr Jlnr. charge. E-911 Burcharge, and the gross receipts tax (a dicadfully unfair tax),

2

1 4'.: 4f,5 C63P 04-02-33 0* • 07PU POO 3 tt 9 3 Amoco Production Company

io

DOE/NARUC National Conference on Natural Gas Use Upstream Issues: Reliability and Production Waste

M. T. Benhaa VP - Regulatory Affairs Natural Sas Group April 27, 1933 Two Key Premises for Upstream Issues Panel

"Production Issues are Less Important Than They Once Were"

.3 "The Fundamentals of the Natural Gas Market Are In Good Shape" Components of Reliable Service

Adequate Resource Base

Co Economic Incentives to Develop Resource Base

Adequate Transmission, Storage, and Distribution Capacity, Flexibility, and Operational Capability

Transactional Arrangements Tailored to Customers' Need for Reliability The "Old" Reliability

Regulated Wellhead Prices

Rigid, One Dimensional Transaction Chain

Balkanized Pipelines

Service Obligations

Result: Shortages and Inefficient Allocation of Resources The "New" Reliability

Market Based Commodity Prices Flexible, Contract Based Sales and Services New Service Providers Integrated National Pipeline Grid Industry Focus on Customer Satisfaction Result: Adequate Long Term Supply at Reasonable Prices with Services Tailored to Customer Needs What is RCRA? Resource Conservation and Recovery Act

• Regulates the Management of Hazardous and Non-Hazardous Waste • E&P Wastes (drilling fluid, produced water, and associatd wastes) are currently exempt from RCRA Hazardous Waste Requirements • EPA Report: E&P Wastes Do Not Pose a Threat to Health and Environment • State and Other Federal Laws Already Cover E&P Waste RCRA Re-Authorization: What Is At Stake

More Stringent Federal Regulation of E&P Wastes would Bring Little or No Environmental Improvements, but would Sharply Curtail Oil and Gas Production - 500,000 oil wells and 200,000 gas wells would be shut-in - First year gas production would decrease 2TCF(or 13%); oil production would decline 440 MMB - 40,000 oil and gas workers would lose their jobs; another 100,000 in supporting industries affected Waste Management Conclusions

States have been Effectively Regulating E&P Waste - Oil and gas producing states have constantly improved their regblatory programs - Industry has developed guidelines for E&P waste management If Regulated Under RCRA, Costs would Skyrocket with Little or No Environmental Improvement

More Stringent Upstream Regulation would be Counter Productive to the Downstream Environmental Advantages of Natural Gas THE MINERAL ESTATE AND NATURAL GAS PRODUCER IN THE POST-636 / ENERGY POLICY ACT ERA

DOE/NARUC National Conference on Natural Gas Use New Orleans, Louisiana April 27, 1993

by

Thomas J. Vessels President, Vessels Oil & Gas Company

358 TABLE OF CONTENTS

I. Presentation by Thomas J. Vessels Eag£ A. State Regulations 6 B. Tax Recommendations 7 C. Regulatory Policy Recommendations 7 D. Section 29 Tax Credit 9 E. The Independent Domestic Producer - Advantages and Disadvantages 11 F. Summation 13

II. Exhibits 1 Comparison of Federally Owned Land - United States (Chart) 1.1 Comparison of Federally Owned Land - Colorado, Utah afld Wyoming (Chart) 1.2 Comparison of Federally Owned Land with Total Acreage of States, Fiscal Year 1989 (Table) 2 Minerals Management Service News Release 3 United States Drilling Activity in 1991 (Chart) 3.1 Drilling Activity in the United States, State by State -1987 to 1991 (Table) 4 Applications for Permits to Drill on Federal Land, 1985 to 1991 (Chart) 4.1 Oil & Gas Drilling Activities on Federal Land, Fiscal Years 1985 through 1991 (Table) 4.2 Well Completions by State. 1987 to 1991 (Table) 5 Acres Leased on Federal Land, 1985 to 1990 (Chait) 6 U.S. Independent - Vital Statistics 7 Majors' Reserves Purchases and Sales, 1982 to 1991 (Chart) 8 Approximate Petroleum Mineral Ownership, TIN R68W, Weld County, Colorado -1983 (Map) TABLE OF CONTENTS (continued)

II. Exhibits (continued) 9 Approximate Petroleum Mineral Ownership, TIN R68W, Weld County, Colorado -1993 (Map) 10 Producing Gas & Oil WeUs, TIN R68W, Weld County, Colorado -1983 (Map) 11 Producing Gas & Oil WeUs, TIN R68W. Weld County, Colorado -1993 (Map) 12 Leasehold Ownership by Horizon - Major 13 Leasehold Ownership by Horizon - Independents #1,2 & Major 14 Producing Gas & Oil WeUs, TIN R68W, Weld County. Colorado (Map) 15 Estimated Capital Costs for Hypothetical Gas Field development by Sector (Chan) 16 Gas Gathering Systems (Map) 17 Gas Gathering System (Map) 18 Major Natural Gas Pipelines in the United States 19 Table of Contents & Executive Summary of Draft Report of the Status of Petroleum Production Industry in California; The Cost of Regulatory Compliance

20 Key Federal Statutes Affecting Oil and Gas Leasing and Access For Exploration and Production 21 Growth of Environmental Regulations - Title 40 of the CFR, 1972 to 1991 (Chan) 22 United States EPA Environmental Enforcement, 1977 to 1991 (Chan) 23 Information on Upcoming Workshop: "Environmental Issues for Oil & Gas Operators - What you Need to Know to be in Compliance" The Mineral Estate and Natural Gas Producer in the Post-636 / Energy Policy Act Era

Current activity in the U.S.A. has been described as a "predicament" in which the country has substantial geologic basins with many producing formations that are only marginally profitable. For this reason, the development of many of these basins has been and continues to be highly sensitive to wellhead pricing. Therefore, long-term - not short-term - production, regulatory and tax policies are critical to exploration maintenance.

The natural gas industry of the U.S.A. is a world class industry. "In the U.S.A. you arc used to supplies and services arriving when they were [sic] contracted for" (Quote from a foreign engineer). We have a high level of technical expertise among both the major, and particularly the independent, gas producers, which enables us to go after the incremental MCF of gas in mature areas. We are further ahead on the learning curve than the gas industry in many other countries because our natural gas resource industry is already mature and has a large market. A large number of giant fields or "elephants" have been discovered and many more remain to be found. Because the market is more or less in close proximity to the resource (both located on the same continental land mass) and there is a relatively mature delivery system connected to the established resource base, any modest increase in price can be expected to quickly resuii in increased activity to recover an incremental volume of gas. If prices are low but stable, efficiencies will quickly develop that will result in additional reserve appreciation and economic activity Two fundamental points to the discussion topic of this conference arc: we have a lot of natural pas in the U.S.A.; and (although usually unmentioned) the majority of gas is privately vs. govemmentally (federal and state) owned. Furthermore, the government-owned natural gas is generally leased and transferred to private interests for development. This is important because many countries have natural gas resources that come on stream only if the government so dictates. Our system of mineral ownership provides the foundation for Order 636 to function. Exhibit 1 is a comparison of federally owned land to privately owned land (tribai lands are included in "Acreage not owned by federal government"). As you can see, most land in the U.S.A. is privately owned. For the most part, the minerals are as well. In Exhibit 1.1, we see the situation can be dramatically different from state to state: Colorado, Wyoming and Utah arc currently thought to have the largest undeveloped gas resource base in the country. Federal policy will affect gas development in these states more than elsewhere. United States drilling activity in 1991 is described in Exhibit 3. Exhibit 4 is a graph of APDs (Applications for Permits to Drill) on federal land from 1985 through 1991. Exhibit 5 shows Acres Leased on Federal Land. The decrease in leases granted was due to a Jease moratorium by the U.S. Forest Service. Prior to the moratorium, we only needed a lease from the BLM (Bureau of Land Management); now, we need to apply for a lease from the Forest Service as well. If the gas industry looks to the western states for increased supply, federal policy, though diminished in gas transportation and marketing, will continue to play a significant role.

To my knowledge, only two countries, other than the United States, have minerals vested in private ownership similar to the U.S. model: the Republic of Ireland and portions of Canada. I hope that this is not true, and that there are more countries with diverse mineral ownership in the hands of the many rather than the few, or worse yet, the one. It is our diverse mineral ownership, combined with a large resource base, that has provided the mechanism whereby market incentives

381 or disincentives can rapidly mobilize or demobilize individuals and companies to increase or decrease the supply of natural gas. If we did not already have such diverse mineral ownership, I doubt Order 636 would have the impact that it is having and will continue to have. Order <536 allows for an environment where a large number of sellers (producers) can meet an increasingly large number of buyers. Had the large number of sellers not already been on the stage, half the show would be missing. Furthermore, we are unusual in that we do not have a government petroleum company extracting natural resources from government-owned minerals. Private companies and individuals can lease federal and state minerals and obtain ownership limits thereto. In many other countries around the world, this system is alien, even in concept. I suggest this system is the primary cause of our industry being second to none. When we look at She major gas and oil companies, we see that the majority' are American. Order 636 will function well if left largely alone, in that there will be potentially more buyers than before, and this should make the economic activity of developing and acquiring gas even more efficient. The identity of the sellers and buyers may be changing under 636. The majors will be occupying a smaller portion of the selling stage and independents will increasingly supply more of the gas requested by the market. So, from the production side, ownership and control is becoming even less concentrated.

Exhibit 6 gives some of the vital statistics of the still large and vital independent sector. Exhibit 7 shows the divestment of the majors of many of their gas and oil reserves, lnformauon is available, documenting the shift in investment away from the U.S. and toward foreign projects, A microscopic view of this transition is described in Exhibits 8 throng)) 14:

Exhibits 8 and 9 show oil and gas lease ownership in Township 1 North, Range 68 West, Weld County, Colorado, for 1983 and 1993, respectively. Exhibits 10 and 11 show well ownership posted for the same area for 1983 and 1993, respectively. Exhibits 12 and 13 show the transfer of horizontal mineral ownership in a typical lease in the described territory during the same period. And finally, Exhibit 14 is a pie chart depicting well ownership for the years 1983 and 1993. This diverse ownership should react as follows in a hypothetical but typical gas field profile, as described in Exhibit IS: The front end costs to develop significant gas reserves is enormous for everyone involved. Pipeline?, both gathering and transmission cost $15,000 - $20,000 per inch mile to construct (Right-of-Way included), with compression horse pow*.. costing around $ 1,000 per unit of horse power, A major field can end up being served by several gathering pipelines, the larger of which may have 1,000-2,000 miles of pipeline and 50,000 horse power of compression. Many gas processing plants large and small are constructed. Thousands of wells are drilled. The total cumulative investment at the point of maturity in a gas field may be something like the following (not. including operating c}

$ jn pillions Gas gathering, 4,000 miles of pipeline 384 (average pipeline dia. 6", average cost per inch mile $15,000) $ 100 Compression, 100,000 H,P. @ $i,000 per H.P. $ 50 Gas Processing Plants $ 120 Transmission expansion to major gas field Transmission pipeline compression expansion to accommodate new fields around margin Total Downstream Costs $ 684 Geological and geophysical inver*ment, research, unsuccessful dryholes and lease acquisition costs ? Well service, technical support and production research ? Drilling, completing and equipping producing wells $1,800 (assume: 7,200 wells at $250,000 per well. This number inc -eases dramatically with depth.)

Cumulative Production cf Pipeline quality gas 1.5 TCF Daily Producti :>n of Pipeline quality residue gas 240,000-300,000 MCFPD The important point to appreciate at this stage is the potential of a mature field. If prices fall, the field as a whole, with all the pieces that rnakt it work, does not go away. It may consolidate ownership and equipment to reducr operating costs, but it will continue to produce at a rate according to incentives. The cream will be skimmed off first (i.e.the most profitable lowest cost, highest volume wells). Some owners and operators of facilities may sell or move to find 'cream' elsewhere. Left in the ground, however, are still large volumes that will continue to be recovered at the low prices that were in effect in 1992. This activity will fall or rise depending on gas prices and gas price stability. Contrast this price structure and its outcome with the price necessary to justify the capital investment involved with finding and bringing on stream a new field. Today's prices may be just what is necessary to bring on new fields of the si?e described. For exampl?: At the very low ^sk ei. * of the investment profile is a rccompletion of a non- produdng some in an old well whose primary *• -ne is depleted or nearly depleted. The cost of this recompletion may be $50,000-$ 100,000 compared to drilling a new well for $2Q0,QQU-$5OO,00Q. TJte recompletion not only involves less capital but it requires no additional gas pipeline investments (assuming the pipe was already laid years earlier for the primary and now partly depleted producing formation). In many established producing fields there exist several uphole zones which are untested. The initial reeompletion, if successful, can lead to a whole new field which may result in new wells being drilled in addition to recomplctioits. The larger the field, the greater the existing momentum which can carry forward activity during nrnes of low prices. Diaring times of low prices, a dollar spent may develop more gas than a dollar spent during a high price (Sworn) period.

A time of Sow gas prices is accompanied by a high yie'd from innovation and increased technical efficiency. The industry is driven to increase gas production for less investment so experience :snd technology are developed that is ultimately exported to the world One conclusion to be reached is that competition and market prices operate efficiently at directing investment activity and motivating human ingenuity. A second conclusion is that the producing segment investment is greater than the downstream sectors combined, Policies that adversely impact production will have significant effects, Natural gas must go through a corridor first or a market membrane before it reaches all those buyers recently released by regulation to come looking for gas to buy. That membrane is the gas gathering and processing sector. There is not any Open Access regulation covering them unless they are jurisdictionaj (and that number is shrinking). There aie more sellers of gas entering into the

Exhibit 16 depicts a competitive gas gathering & processing environment. Exhibit 17 shows the same gas gathering and processing system, in a less competitive environment. In the pas:, other countries, especially those with centrally planned economies, have limited competitive market phce effects on their natural gas industries. Within the last few years it has become evident that this decades long trend is reversing. To the extent that another country's natural gas industries are decentralized, rationalized, privatized or somehow allowed to be influenced by competitive market forces, when that was not previously the case, those country's gas industries will become more competitive with that of the U.S.A. Our nation should therefore be viewed a* a competitor with the other current and potential natural gas producers in the world. Will we produce and develop our gas, develop our technology and expertise, advance our environmental and safety systems and procedures or will our competitors? Within the U.S.A., due to the federal Nature of our government, states are also viewed as competitors in this arena. Some stttc, pursue different policies at the regulatory and/or the fiscal level Given the fact that some states may have more gas reserves, more mature production, gathering systems and gas located near large markets than other states, it is easy to see that states - as well as nations - do not have equal opportunity to achieve economic, robust natural gas activity.

To use a concrete example: a large relatively undeveloped gas field in a remote region served by an immuiore, fledgling, infrastructure may provide little resource and languish, while the mature field described above produces more economic activity, employment, and tax revenues for its community. Exhibit 18 depicts the Interstate Pipeline Network as it existed in 198S. Much has transpired since then, but the great basins of the west are obviously less well placed than those in the Gulf Coast and mid-continent to compete for gas market share. A tax, fiscal and regulatory policy that creates a partnership between government and industry may be the best for all parties concerned. Currently in the U.S.A., there exists, at both the federal and state level, regulations that were enacted, on the one hand, during a bygone era of supposedly low energy supplies, and on the other, a new era of environmental concern. These taxes and regulations are being adjusted differently by different states and the federal government, with different effects.

Now, employment is down and our expertise and technology are being exported where they are being effectively employed and as a result, creating more competition. We will ultimately thrive on competition but some regulations create disincentives which counter the needs of the gas industry to respond to cycles in the economy.

Regulations that adjust with economic cycles could be beneficial and result in a higher level of employment, continued economic output from marginal or depleted "stripper" facilities and maintain a more consistent revenue base for state and federal government. Is this realistic? I believe the more sensible approach is a system which sends dollars down a pipeline in the necessary amount to attract supplies and requisite services. STATE REGULATIONS

An analysis of exploration activity must first address the primary factors • price and geology. Many states do not have a significant production price advantage. States are unequal in geologic potential. Same states may have low production tax rates, but lack apparent subsurface hydrocarbon potential. Favorable regulations and taxes alone will not a gas field make. Light production regulation and variable taxes are positive incentive factors that can help sustain modest exploration activity in areas where geology or economics are weak. Some states' natural gas production had the gas price free fall of the 80's. One must conclude that higher level production taxes and regulations existing in some states have been a major disincentive to greater exploration activity during recent years of low prices. It can also be argued that the aggressive attitudes of taxing agencies in these stales to maximize income by agency interpretation of valuation rules is at least partially to blame. Do higher production taxes reduce production? An unqualified affirmation may be too profound unless the factors of product price vind geology are removed from the economic model. Would you drill a comparable prospect in a state with higher taxes and more regulations over a state with lower taxes and fewer regulations? These are several examples of where consistent, favorable production tax policies are coupled with only moderate geologic prospects, Utah is in the mid-range of states based on production taxes as a percc/t of value. Its tax policy and incentives for prolonged production life •AK commendable; the state's severance tax exemption of stripper wells producing w MCF per day or k\ss is the highest in the nation. Despite the favorable tax environment, Utah is burdened by subsurface geology which consistently reflects the highest per foot drilling costs in the region. The maintenance of a significant level of exploration/production in Utah is supported by prudent production tax policy. The changes to Utah's severance tax policy in response to the recession in the petroleum industry may be unique. In addition to the stripper gas exemption, Utah provides a J 2 ir?nth severance tax exemption for wildcat wells and six months for in-field development v\ elJs. On other gas production, an adjustment was made away from an across the board 4% severance tax to a 3% tax for gas sold at $1.50 per MCF or below and 5% for gas sold for $1.51 and above.

Some states articulate in their policies, statutes and charters that they do desire to promote and develop their natural resources. They need to know they are automatically competing with other countries as well as other states for markets for their natural resources. A state policy of husbanding of resources will, in a competitive environment, inhibit or prevent a state's resources from providing wealth for its citizens, while a state without such a policy will reap these rewards as a result of providing incentives to produce. A subset to this issue is the state whose gas production is further from the market centers, and who therefore may have to provide more incentives to its producers to compensate for inferior wellhead prices resulting from added transportation costs. A state that is a consuming (as well as producing) state, still gains by developing ;ts own resources and training its own residents rather than importing gas and expertise from outside the state.

It is no surprise to those in the industry that California has had a difficult regulatory environment for the petroleum industry. On March 26,1993, the California Department of Conservation received a rpport they had commissioned on the cost of regulatory compliance by the petroleum industry. Included as Exhibit 19 is a Table of Contents, Executive Summary and the Recommendations of the Study. A list of options to the stales interested in promoting the gas industiy with a balanced production policy would include the following:

• Reduced taxes for the initial production from wells that are wildcats. Wildcats will bring new field discoveries and overall increase in tax revenue from the subsequent development wells. • In high cost areas more moderate tax reductions can be utilized to stimulate in field development drilling or recompletions in non-producing formations. • A graduated severance tax where the tax falls to a lesser percentage of value in times of low prices and rises to a higher percentage value in times of higher prices. This will encourage producers to keep wells on production during the downturns in the economic cycle. The transition price could be adjusted to published GNP deflators or other appropriate indices. • Tax rwudie ns or exemption for marginal "stripper" wells producing under some level deemed near an economic limit, • Reduce the property valuation on equipment during economic downturns to recognize the fall in used equipment value. • Reduce or eliminate property valuation on equipment installed as part of environmental protection and safety devices. • Return a substantial portion of the revenue thus received to jurisdictions governing the areas from whence die production comes. Publicize the benefits as well so they are recognized by the local population and political support is thereby gained for the industry. The public will then be more informed about the consequences of new regulations or taxes on their economy.

Regulatory Policy Recommendations:

• Support the appropriate regulatory agency in its efforts to achieve credibility as a fair minded and responsible overseer of industry activity, especially environmental and safety issues. If the industry can adjust to a higher level of balanced regulatory requirements, economic activity can be mainlined at a rational level. • If gathering pipeline regulation becomes an issue, allow the state Oil & Gas Commission (OGCC) to regulate rather than the state Public Utility Commission. State and local governments are under varying degrees of financial pressure. The dialogue with the states on tax policy should be presented in terms where we are all winners. It should be demonstrated that the citizens of the state are the beneficiaries of additional revenue from natural gas production taxes and royalties through their use to better fund the services provided by the state and local governments. Education in particular is the recipient of a large portion of production taxes in many states. Those government and industry leaders interested in obtaining revenue for education and other services should be made aware of the benefits of an incentive driven tax policy that rewards all parties involved.

36 f As we indicated earlier, many states do not have ultimate control over much of the natural gas resource they can potentially benefit from. Exhibit 1.3 is the Minerals Management Service News Release of March 17,1993 presenting the oil and gas revenue returned to the state. In general, 50% of oil and gas revenue is returned to the state from which the revenue came.

Exhibit 2 is a copy of the Mineral Management Service News Release, dated March 17, 1993, which summarizes the states' cumulative share of 1992 revenues collected for mineral extractions from federal lands located within their borders.

As you may remember from the exhibits, federal leasing has declined. More federal regulations overlay state regulations. Federal environmental regulations may land on the industry, whether on private or federal land. On federal leased minerals even more rules will be in force.

Exhibit 20 is a list and description of major federal statutes and regulations, and a brief description of their impact on the gas industry. Exhibits 21 and 22 describe the growth of environmental regulation and enforcement. Finally, as Exhibit 23 evidences, there exists a thriving industry of environmental compliance, I suggest the federal government do as the state of California has done, and study itself and its own effect on the gas industry. SECTION 29 TAX CREDIT

Some analysts have said drilling for noneonventional non-associated gas accounted for as much as one third of all U.S. gas wells drilled in 1990. Federal income tax incentives have provided the biggest impetus for growth of net gas reserves in the U.S. The most valid measure of the lax incentives success is the current contentiousness within the industry that subsidized nonconventional gas production is unfairly competing with conventional gas.

Section 29 tax credits have been a success story in Colorado, New Mexico, Utah, Texas, West Virginia and many other states. Section 29 is directly responsible for the increase in tight sands and coal bed methane gas development. All is not well in Gas Town, however. Digress back to the primacy of economic factors of product price and geology. Section 29 tax credits were losing momentum as an exploration incentive because of gas price erosion. The tax credit for coal scam gas was worth 900 per 1,000 cubic feet of gas and did not play well with gas prices in many areas that were less than $ 1.00 at the wellhead.

Income tax credits provide benefit only if regular taxable income exists. As effective as federal tax credits have been, there is a powerful disincentive which offsets much of the upside of nonconventional fuels drilling ventures. Something besides price is hurting drilling ™ something which can be attributed to reformed U.S. tax law. The effect of the alternative minimum tax ("AMT") on the main income tax incentives for drilling cost and capital recovery (current year expending of intangible drilling costs (IDCs), and the allowance of percentage depletion) is one of neutralization. Producers, of course, can partially recover AMT tax payments through credits if they later achieve sufficient regular taxable income. However, many producers of nonconventional fuels are not adequately profitable to generate regular income sufficient to exceed alternative minimum taxable income. Tax crodits earned but not taken in a given year can often not be carried forward for use in the following year when income may be more accommodating. The limitation of income tax based incentives such as the Section 29 credit is exemplified by decreased drilling and shut in production. While there may be disagreement as to the wisdom of the Section 29 credit, it is clear that the Section 29 tax credit has been effective in its goal of encouraging development of non- conventional reservoirs. The credit is particularly attractive from the government's standpoint, because it has been effective without waste or expensive government administrative costs. Section 29 credits are earned only when gas is produced. No credits are earned for unsuccessful efforts. It is debatable as to whether or not most of the reserves subject to the credit would have been developed without the incentive. However, there can be no question that development of qualifying production has been expedited due to the credit The credit is partially responsible for the current robust gas supply outlook. The Section 29 tax credit had one problem within the federal tax code. The problem related to the limitations on its use imposed by the alternative minimum tax. The federal tax code should have been revised to allow for full realization of the Section 29 tax credit in concert with making the credit permanent, to enhance the potential stimulus to drilling activity. I have been told by tax specialists that the tax system was not originally designed as a mechanism to offer economic incentives. I don't believe it should be used as one. Once economic hcensives betome involved, then politics become even more involved, Another radical position that could be taken is to join forces with the proponents of tax reform and support a pure flat tax in place of the convoluted politicized tax code of today. Taxes on consumption and excise taxes on imported fuels could be instituted to articulate a more intelligible policy. The result: • Gas producers could make their decisions based solely on economic merits independent of tax considerations. • The U.S. government receives additional excise tax revenue.

• Domestic drilling increases. • U.S. government jobs are created. • U.S. government receives additional revenue from payroll tax

10

370 ADVANTAGES AND DISADVANTAGES OF THE INDEPENDENT DOMESTIC PRODUCER

Advantages 1. Large data base from which to look for large to small oil and gas producing prospects. 2. Large mature technology that continues to grow and be refined to enhance our ability to increase and prolong production from current producing fields at lower cost and to economically produce heretofore uneconomic petroleum reserves. 3. Proximity to market for our products (not true in all cases, especially with natural gas and some natural gas liquids that can be geographically remote from markets). 4. Market infrastructure is already in place (pipelines, refineries, gas distribution systems, motor fuel pipelines, railcar facilities, trucking networks, petrochemical manufacturing and distribution networks, etc.). 5. A mature market Except for natural gas, other products have usually been priced at free market prices. The market network of today includes futures commodity markets so relatively unsophisticated producers can track prices.

6. Large resource base privately owned as opposed to other countries where the government is the major mineral owner.

Disadvantages 1. Higher exploration costs when compared to other countries with larger oil and gas fields that are still undiscovered. At least, this is the perception.

2. Lower profit margin per barrel of oil when compared with competing sources of foreign oil. 3. Uncertain regulatory liabilities and policy directions. 4. Lack of financing sources for investment. 5. The largest portion of the.petroleurn resource portfolio, natural jas, has been regulated for most of its history, so is now having to catch up for market share versus other sources of energy. Natural gas and oil must compete not only with foreign sources of petroleum, but also with coal, nuclear, geothermal, solar and wind power. These competitors may not seem significant today, but the situation could be far different from the vantage point of ten years hence.

6. Many independent producers are still learning to market natural gas as a commodity.

11 7. Uncertainty of public lands policy direction; this can inhibit the commitment of even initial exploration activity in certain prospective public lands due to the belief that the risk of not being allowed to develop the prospect is too great. Moratoriums in the Rocky Mountains on drilling due to alleged threat to local wildlife, such as the bighorn sheep, are common,

8. The Alternate Minimum Tax.

12 SUMMATION

The worldwide fall in energy fucj prices of coal, gas, oil, and uranium has put in place a competitive world market for fossil fuels in particular. Fuel producing countries worldwide are attempting to bolster their economies and provide incentives to attract development for their natural resource industries. Where market forces arc allowed to work, the efficiency of energy use and extraction improves. It is obvious that proponents of markets forces are increasing in number. Industries will hav-s the ability on a worldwide scale to pursue the most cost effective purchase and development strategic?. U.S. natural gas producers will be decreasingly subsidized by inefficient costly foreign government controlled natural resource extraction industries.

If we want to perpetuate healthy economic natural gas extraction and consumption, we need to stay competitive and price sensiuvc to competing energy sources. We arc competing with every fossil fuel producing nation in the world. Within the US, the states compete with each other through regulation and tax based (production, income, excise, etc.) incentives. The US has a huge resource base, the nature of which is only now beginning to be understood. It is primarily spread over large areas comprising prospects which arc currently only marginally economic on an individual basis. Properly placed incentives can motivate our industry to become technically more proficient as we uncover layer after layer of increasingly larger reserves. This expertise will in itself be a service we can and arc marketing worldwide. Some countries and states have followed the misguided notion of husbanding their resources by restrictive taxes and regulations. The reality is that without proper tax incentives and policies, some countries (or states, for that matter) may never produce their resources to the benefit of their citizens while those countries or states aggressively supporting their industries will achieve optimal levels of production and revenue. In conclusion - if a conclusion can be drawn from all of this -certain kinds of tax incentives, whether state or federal, are a justifiable component within a tax policy, but the primary goals must be to achieve overall fairness and offer the opportunity to assume a reasonable return on investment to an investor who has an increasingly international array of choices as to where the investment S goes.

13

37.* I y.U>hl'< !

Fiscal year 1989 Acreage not owrtedT)y Federal Government 1,609,185,163 )

Government acreage 662;i58,196

Based on data from General Services Administration. Bureau of the Census, U.S. Department of Justice Cxhibit I.I

I'rnudcil by Hncky Muuitliiiii Oil & V,as Exhibit LANDS OF THE UNITED STATES AND POSSESSIONS

TABLE 4. - Comparison of fsdarally owned land with total acreage of Slates, llteal ytur

Acreme owned by pie Federal Govsmmant Acreege not Acquired owed by Toial Percent by other Federal Fedora! acreage ot .../.owd by Pub'ie Domain rnolhods lOtill Government -iCl'"tSfflSDJ

Alabama 3,087.3 646,770,3 S49.8S7.6 38,188,548,4 32,678,400 1.S83 Alaska . ... 846,074,568.9 1,787,675,6 847,808,844,5 117,679,355,5 365,481.600 67.602 Amona 31,010,306.2 481.0S8.6 31,491,364,8 41,196,635.2 7C.6B8.000 43.324 Arkansas 1,080,423.5 2,340,637.4 3.421,060.9 30,178,899,1 33.599.360 10,188 California 57,007,997,3 4,034.580.4 61,048,577.7 39,164.142.3 100,806720 60.917 Colaracks 21.511.665.8 1,135.972.6 88,647.838.4 43,837.921.6 66,485.760 34.064 Cannaeteut 13.910.1 13,910.1 3,181,449,9 3.135,360 0.444 Delaware 30,3597 30.3597 1.235,5S0,3 1.265,920 2,398 Distnet d Columbia ,,, 8.6 10,8637 10,878,3 88,1677 39,040 27 649 Ftanda 813,8350 3,142,308.5 3,355,543.5 31,365,736 5 34,721,280 9.664 GOSWT 8,298,378,5 2,292,378.5 35.002,981,5 37,295,360 6.147 Hawai ,. 268,747,8 408,076 1 676,873.9 3.48B. 776,1 16,485 tdaha 32,305,837,3 816721,3 33,181,958.6 19,811,161.4 S2',933li80 62,573 Utimeis 411,2 493,467,1 483,878,3 35.301,321 7 35795,200 1,380 Intiiarin , 718,0 469,082,0 469,794.0 88,680,606,0 23,158,400 8,089 Iowa - • ., ... 3407 168,793,1 159,133,3 35,701,346,2 35,660,480 0,444 Kansas , .... 1.752,5 €88,092,0 689,844,5 51,880,875 5 52,510720 1,314 Keniuefcy 1,391,208,2 1.391.2088 84.181,111,8 25,512,320 5453 Louisiana 21,938 3 6,515,655.4 6,537,5877 88,330.252.3 28,867,840 88,647 Marco 58.5 152.6194 158.677.9 19.69S.0021 19,847,680 0769 Maryland 196.921.4 196,921.4 6,188,438 6 6.319,360 3,116 Massachusetts 82.568.6 82.562.6 4,958.317,4 S.O34.08O 1,640 Michigan 295.431,1 3.269.345.8 3,564,776.9 38,987,383,1 36,492,160 9.769 Mrtnesota 1,163.766.9 1.288.916.8 2.386,683,7 48.et9.07b 3 51,805.760 4.661 Mississippi 3.S81.1 1,666,942.6 1.670,5237 88.558.196.3 30,882.720 5.527 Missouri 3,049.3 8.027.455.6 8,030.504.9 42,817,815,1 44.848,320 4.589 Montana 23,4S5,755.2 2.406.740.9 25.862,496.1 67.408.5439 93,871.0-JO 27.788 Nebraska 248,344.1 470.260.1 718.604.2 48,313,0758 49,031,660 1,466 Navatfa 57.421.258.8 38 >.955.6 S7.803.20B.4 18.461,111.6 70,854,380 88.865 NEW Hampshire 38 754.406.9 754.4107 5,014.549 3 5,768,960 13,077 New Jersey 103.1 135,357.9 135,461.0 4,677.979.0 4,813,440 8,814 Now .Mexico 21.950.448.0 3.796.860.3 85,747,308.3 58,019,091.7 77,766,400 33.109 New York 65 9 283,216.7 883.888.6 30,457,677,4 30,660,960 0.788 North Carolina 1,140,931.3 1,140,931.3 30,861.9487 31,402,880 3.633 North Dakota 245,831.3 1,718,954.3 1,964,785 6 42,487.694.4 44,458.480 4.420 Oho , , , 134 4 321,595 8 325,730 2 25.900,3498 86.288.C30 1,287 CWahoma 89,112.9 784,891 0 874,0039 43,813,676.1 44,087,680 1.938 Oregon .... , 28,457.127.8 1,211,625,1 29,668,758.9 31,989,967.1 61,598,720 48.165 Ponnsyivama ... 166 640.921 9 640,938 S 88,163,541.5 £8.804,460 8,225 Rhode Isiana . 4.685 6 4.685.6 678,434 4 677.120 0.692 Souih Caroi.na 433.V71.4 433,771.4 18,940,308.6 19,374,080 8,239 Sauft Dakoia 1.589,3677 1,154,3948 2.743.762.5 46,136,157,5 48,881.920 5.613 Tennessee 1,382.2152 1,322,215.2 £5,405,46* .6 86,757,680 4.947 Tews 3157 8,844,627.7 2,844.9434 t65,37r,65S6 168,817,600 1.691 Irsh 32,151.1246 1,460.271.2 33,611,395,8 19,065,564.2 58.696,960 63.788 Venrscni .... 354,917 0 354,917 0 5,581723.0 5.936.S40 5,976 Virginia . ... 420 1,918.302.3 1,916,344.3 83,577,9757 25.496,320 7.S24 Wasfv.ngtsn 11,843.780 9 1,189,369.4 12,373,150.3 30,380,6097 48,693760 28,981 West Virginia 2,039,135.6 8,099,135.6 13,311,4r>4.4 15,410,560 13.621 Wisconsin 10,788 8 1.895.028.6 1,905.815.4 33,105,3B.1.6 35,011.200 S.443 Wyemng 30,048.4567 358,801.9 30,407,258.6 31,935,781 4 62,343,040 48,774

T^ial. _ „ 597.679,583,6 64.279.613.3 66!?. 158.196.9 1.609. IBS. 16a 1 8.S71.343.360 29.153

Ntt* - Th:i (Ale ncrMrra llx wot ounwM «»!• nt'H* (ram «w G»^*t*i SWVCM WnvrailWon O«a AM not mttutf* triune MM

n Mnrn»'.;KiBn.Gsmrmwnn>mRM!Pnpiiiyf>oHT. lti , NS , Boom 1J0O, W««h«>|t«i. OC 50*05 Provided by Rocky Mountain Oil & Gas Associalil r

M'R :MMFi: JATE RELEASE Michael L. B«ugher '303)1114162 Mar*;.*- ;", l^yS, ThoroatC DeR«co 20U20M983

35 STATES COLLECT S472 MTU .ION AS ft SHARK OF FEDERAL MPT'SAL REVENUES

"":> 3 i j n«!!;i-!s! ai *hi> Interiors Minerals Management Sennei" (MMS11 today *nji<9u?u*e<5 (Ji«i ••.-*; .;.. • IT,.* ,;u y r^prewnu d«* svav* ? ,:S:;,\(.AC *«nr(« at vh** Jf*^2 rovenu^s eolleetcd for mineral extraction! from fadernl Jands .<«!*! v. •',„• :r,»-,it n federal and Indian I»n4t Oubuniem^nts are *n«dp u* n*u^ m :: • •.; > •-»- «» U^iri.^fs. rpius, royalties and other revenue* are collected *A >:,.(!•• ^ ••"uilHi v? a share of the mineral revenues collected from federid Sands «v.ji'.*»d w.U r M. >T*I:« > jx-iij:,:«r;f.» Far ihe majority of federal Jands, states and the federai eovejT.fwn! har» i ?h . •• .- ' j • Ti-*r,i u; the ihe Reclamation Fund for water projects, and 2 ' [ x iu> •-* - '".- Trvavurv U«i« <-xcepuon, Alaska, Rets a 90-percent share, as prescnb«>d by tht Aisska A r * • T: .u.r.t<: c\-;.r;|. MMS Director Carohta Ka3Jaur • :•-'..: asia! slates with federal offshore tracts adjacent to thejr «eawart5 bcundan^f f • - • • : T" :;i **"• r'sn^raS royaSlies as we!)," Ka.'.'aur added. il: l*;'.. :t\f >;nu>s -Wvommg, Ne* Mexico, Colorado, Utah and California •• »«<:«• wo TTJCT«' ihar. *•*•<• -••,,• ?' :,"•«• *,!-w: r«v»R>ips distributed to states by MMS.

\ ti",,r>i $4.iaT;,;»1386 Louisiana $8,6:8,05582 Oregon U~A"* •\;i< ^.<. *?^57>0: "sC! Michigan tgOO.Od.i.eo PennsyK-ania *t;.rWti .Vjv-u $122.5^52'^ Munneafita J10TM South Dakota U*'Z,~M Mx..'-.»« $:,:i4,£ift.2fi Mississsppi $172,«K).13 Ter»n«s«ee $R* •••"«:»:" ",.a SU<\9r«,4ft352 Missouri t203,798.19 Texas *I«,-^" JSfi '..:.;*-,, «.,703,02* 12 Mar.tana 520,0*^30,02 UUh K::;-*aa S;i5.64O24 Nevada $8,136,227.?5 Virgins* '•„. «(;:a S51S9 Sew Mexico tlli,490,646J22 Wuhington :.:•-.'.•' $:v.)09.7M35 North Carc3sr.« J169.23 West Virginia :••:,.» vj-. 83T.62334 North Dakota $4,705^27.39 Wjieonssn Ka.;;Ms- S:jt»3,450.76 Ohio |M7,76L23 Wyoming k-••ri-'.v £!O,r^S$? Oklahoma $1,417,62561 ToUl

MMS-RMP • I \ III III I

Tribal wells drilled 342(147%)"

-, fi I - Federal wells drilled 3349(14.42%)

ftt

Based on data from ihe Articrkan Petroleum Institute, tasic Petroteum, Data Book, Biiremi of LiRd Management Exhibit 3.1 Drilling Activity In th* United States by State of4

1987 198B 198S 1990 1991

Alabama Federal 5 3 4 20 24 Indian 0 0 0 0 0 Total 272 333 507 1,053 845

Alaska Federal 0 0 4 10 3 Indian 0 0 0 0 0 Total 96 144 119 119 96

Arizona C M O Federal 5 C M O 1 0 Indian 0 7 0 Total 5 8 1

Arkansas Federal 7 11 29 20 10 Indian 0 0 0 0 0 Total 413 430 313 321 226

California Federal 1S5 71 224 199 268 Indian 0 0 0 0 0 Total 2,538 2,133 1,826 2,253 1,753

Colorado Federal 85 199 211 289 218 Indian 44 127 141 169 130 Total 890 1,033 930 1,126 712

Florida C O Federal 2 4 C M O 4 Indian 0 0 0 Total 9 11 7

Georgia Federal 0 0 0 0 0 Indian 0 0 0 0 0 Total 1 2 0 0 0

Idaho C O D Federal 1 1 0 0 Indian 0 0 0 0 Total 1 2 0 0

Illinois Federal 2 0 0 5 5 Indian 0 0 0 0 0 Total 1,323 1,230 831 773 577

Indiana Federal 0 0 0 0 0 Indian 0 0 0 0 0 Total 352 279 198 154 119 low Federal 0 0 0 0 0 Indian 0 0 0 0 0 Total 1 1 5 2 0

Provided by Rocky Mountain Oil & Gas Association

378 Exhibit 3.1 Pajje 2 of 4 1987 1988 1989 1990 1991

Kansas Federal 4 14 14 18 16 Indian 0 0 0 0 0 Total 3.236 3,005 2,578 2,874 1,995

Kentucky Federal 0 0 14 6 32 Indian 0 0 0 0 0 Total 1,201 1,197 1,041 857 493

Louisiana Federal 5 11 24 5 10 Indian 0 0 0 0 0 Total 2,404 2,253 1,689 1.854 1,181

Maryland Federal 0 0 0 0 0 Indian 0 0 0 0 0 Total 1 2 0 0 0

Michigan Federal 7 12 4 B 7 Indian 0 0 0 0 0 Total 537 640 850 990 569

Mississippi F*d*ral 24 29 26 25 32 Indian 0 0 0 0 0 Total 317 345 292 278 194

Missouri O C M Federal 0 0 0 Indian 0 0 0

Total 18 0 O 12 24

Montana Federal 158 113 145 182 146 Indian 10 11 5 20 12 Total 298 355 236 333 235 fJubraska Federal 24 5 3 0 4 Indian (; 0 0 0 0 Total 204 135 103 126 114

Nevada Federal 27 26 54 45 51 Indian 0 0 0 0 0 Total 27 26 54 45 51 firnu Mexico ' Federal 821 878 875 1,707 1,541 Indian 100 110 45 29 34 Total 921 988 923 1,736 1.575

New York Federal 0 2 1 2 2 Indian 0 0 0 0 0 Total 254 179 104 9 2 Exhibit 3 Page 3 of 4 1087 1BB8 1889 1880 1981

North Carolina Federal 0 0 0 0 0 Indian 0 0 0 0 0 Total 1 0 0 0 0

North Dakota Federal 41 39 17 55 52 Indian CV I 6 3 6 6 Total 186 256 182 257 171 Ohio. Federal 15 4 7 20 43 Indian 0 0 0 0 0 Total 1,794 1,382 1,264 1,260 562

Oklahoma Federal 9 32 23 14 18 Indian 104 95 83 51 60 Total 3,883 3,368 2,906 2,831 2,228

Oraoon Federal 0 0 0 0 0 Indian 0 0 0 0 0 Total 10 18 14 0 7

Pennsylvania Federal 0 3 140 0 0 Indian 0 0 0 0 0 Total 1,141 1,039 884 455 66

South Carolina Federal 0 0 0 0 0 Indian 0 0 0 0 0 Total 1 1 0 0 0

South Dakota Federal 3 18 14 15 9 Indian 0 0 0 0 0 Total 15 20 16 15 9

Tennessee Federal 0 0 24 0 0 Indian 0 0 0 0 0 Total 165 85 60 36 17

Texas Federal 28 17 15 30 16 Indian 0 0 4 3 0 Total 11,259 9,978 8,503 8,868 7,947

Utah Federal 175 161 114 114 223 Indian 24 39 37 41 S3 Total 199 200 151 155 316

Virginia Federal 0 0 0 4 18 Indian 0 0 0 0 0 Total 21 29 22 6 18

3Si Exhibit 3,1 Page 4 oM 1887 1988 1989 1900 1991

Washington Federal 0 3 1 0 0 Indian 0 0 0 0 0 Total 1 3 3 0 1

Wast Virginia Federal 0 2 48 7 3 Indian 0 0 0 0 0 Total 862 66S 789 712 537

Wyoming Federal 849 786 698 936 594 Indian 2 11 0 2 7 Total 851 797 698 938 601

TOTAL: 23.225

TOTAL INDIAN: 342

TOTAL FEDERAL AND INDIAN: 3,691

(Source: API Basic Petroleum Data Book Bun)

API data doa* not include wells drilled to less than 50 feet. Also, API data is revised, sometimes significantly, with subsequent quarterly reports. Therefore, API's data is essentially incomplete, and they consider it to be estimated numbers.

NOTE: IPAA drilling statistics are derived from API's statistics and quarterly drilling reports. Therefore, IPAA's statistics are also incomplete. Inhibit 4 Applications for Permits to Drill on Federal Land

3318 3000. 2617

1969 2000 1886 1772 1851 1486

X

1988 ; Ym 1990 1991 Based on data from Bureau of Land Management Quarterly Ruid Mineral Reports

K.xkv Oil >V (..is Exhibit 4.1 Pane 1 of 7« PUBLIC LAND STATISTICS

TABLE 43.—OH and gas drilling activities on Federal land, fiscal yew T985

Geographic APOs' New noies Producible Plugged and State asoroved started comolelions aDanctoned Aaoama • Aiasxa S 3 j Arizona 2 5 Arnansas 5 '6 : Caiicnia 393 2'3 •7? '5 CoiO'aao •96 B3 >2? 31 laano 2 ' Kansas 7 6 .outsiana 2- '9 • Mcnigan 2 MlSSISSIODI •6 MlSSOU" 6 3 2 Montana 2*0 •65 l'S 72 NesrasKa 2 2 Nevaoa 39 ">? 3 •4 New Mexico • 258 369 350 -8 Nor.n OaKoia •83 36 16 Ohio 3 3 OK'anoma 5 6 Oregon 3 Soum OaKoia 9 9 5 Texas 14 3 9 Ulan 209 103 99 68 West Virginia 2 Wyoming 1 001 381 175 237 Eastern States 63

Total 3.318 l 168 l 166 S<3

'ADpiications lor ssrr.i.t to ami (APOs) are handled by administrative otlices (e.g., the Eastern States Otticei, while the starts, cor-oietions. and abandonments shown in the three columns lollowing are portrayed by geo- graphic State (e.g.. Alabama. Arkansas. Louisiana, etc.).

TABLE 44.—Co. uing oil and gas activities on Federal lands as of September 30, 1985

Number ol Number o> Number ol producible producible Geographic units m and service and service Slate effect holes comDlenons

Alabama 2 4 5 Alaska . 9 116 ?48 Arkansas 2 73 '07 ;aiilorma . 36 4.502 4 513 Colorado l'7 2.436 2 4'.! daho . 3 Kansas 2 !36 169

70 PUBLIC LAND STATISTICS

TABLE 41 .—Oil end gas drilling activities on Federal land, fiscal ytar 198$

Geograpmc APDs New holes Producible Plugged and State approved* started completions abandoned

Alabama Alaska Arizona 1 Arkansas .... 28 26 S California 189 28 26 Colorado 194 211 s Florida 1 10 idano Kansas 4 4 Louisiana 7 9 Mississippi 6 2 4 Montana ttS 78 73 17 Nebraska 3 1 3 Nevada 23 20 14 20 New Mexico .. 654 534 643 61 North Dakota . 42 37 17 Ohio 1 1 Oklahoma 10 Oregon South Dakota . 7 7 Texas 10 7 3 Utah 85 79 115 Wyoming 612 467 372 391 Eastern States 72

Total 1.866 1.553 1.530 656 'Applications lor permit to drill (APDs) are handled by administrative offices (e.g.. the Eistern States Office), while the starts, completions, and abandonments shown in the three columns following are portrayed by geographic State (e.g.. Alabama. Arkansas. Louisiana, etc.).

OCo OA •) Exhibit 4.1 BUREAU OF LAND MANAGEMENT PROGRAMS Page 3 of 7 ?3 Energy and Mineral Resources

TABLE 43,—Oil and gas drilling actMtlos on Federal land, fiscal year 198?

Geographic APDs New holes Producible Plugged and Stale approved4 started completions abandoned

Alaska . , . 1 3 Arizona 3 3 2 Arkansas 7 it 8 115 106 161 121 Colorado S3 27 27 99 Florida 1 1 idano 1 2 3 8 2 4 Michigan 1 1 Mississippi 8 7 7 Montana . . . 85 76 108 39 NeDrasKa 3 6 Nevada 17 13 2 8 512 353 334 112 Nortn Dakota M 20 41 Ohio . ... 4 10 Oklahoma A 10 72 Soutn Dakota , . 3 Texas 12 21 6 Sjtan 124 81 117 59 1 1 Wyoming S34 302 272 392 Eastern States 31

Total 1,466 1,023 1,112 982 •Applications lor permit to drill (APDs) are handled by administrative offices (e g . tne Eastern Stales Ol'ice), while the starts, completions, and abandonments shown m tne tnree columns following are pomayed by geographic State (e.g., Arkansas, Florida. Kansas, etc.). Exhibit 4.1 Page 4 of 7

BUREAU OF LAND MANAGEMENT PROGRAMS 73 Energy and Mineral Resources

TABLE 44.— Oil and gas drilling activities on Federal land, fiscal year 1988

Geogrspmc APOs New holes Proaucioie Plugged ma Stale approved0 started completions aeanconoa

Alaska 3 Arizona 1 Arkansas 5 California 66 38 3 Colorado 119 26 Florida 1 icano l Illinois I I Kansas 7 2 2 Louisiana 5 2 l Michigan 5 5 1 Mississippi ... 17 2 15 Montana 97 66 SO 21 NedrasKa 9 7 t Nevada 19 16 3 n New Mexico . 685 462 366 36 North Dakota 28 13 7 Ohio 5 9 Oklahoma ... 53 33 10 Pennsylvania . 3 3 South Dakota 5 " 5 Texas 11 9 2 Utah 145 107 69 3-1 Wasnington .. 1 West Virginia . 1 Wyoming SS9 493 291 21! Eastern Slates 61

Total 1.772 1.526 988 390

'Applications lor permii to drill IAPDSI are handled by administrative ollices (eg . the Eastern Slates Olficei. while the starts, completions, and aoandonments shown in the three columns loiuwmg are portrayed by geographic State (e g.. Arkansas. Florida. Kansas, etc ) Exhibit 4.1 Page S of 7

68 PUBLIC LAND STATISTICS

TABLE 41 — Oil and gas drilling activities on Federal land, fiscal year 1989

APDs New holas Producible Piuggec ana Geographic State approved* started completions abanac-ec

Aiaoama 5 3 1 Alaska .... 2 2 l Arkansas ... . 7 13 California 227 105 106 S 140 98 83 16 1 1 1 Kansas 7 7 2 6 3 Louisiana . 7 9 2 Michigan 2 5 15 5 9 Montana 90 77 40 10 NeorasKa , , . , 2 3 Nevaaa 32 23 9 10 New Mexico 805 441 447 2" New York t North Dakota 6 7 5 2 Oklahoma , ...... 13 10 3 1 South Oakota . . ,., 4 2 2 Texas 7 3 Ulan 59 SS 35 16 Washington . 1 2 West Virginia . 47 Wyoming 453 347 169 H6 Eastern States . , 37

Total 1.851 1.231 1.006 233

'Applications lor permit to drill (APDs) are handled by administrative offices (eg., the Eastern States Office), wmle the starts, completions, and aDandonments shown in the three columns following are portrayed by geographic Slate (e.g.. Arkansas. Florida. Kansas, etc.). Exhibit 4.1 Page f of 7

BUREAU OF LAND MANAGEMENT PROGRAMS 71 Energy and Mineral Resources

TABLE 44.—New oil and gat drilling acllvltl9$ on Fodarat land, fltcal yaar 1990

APOs New holes Producible Plugged and Geographic State approves* started completions abandoned Alabama 9 to j AlasKa 2 2 4 Arkansas U 12 6 4 156 124 72 98 Colorado 203 149 117 14 Florida 1 2 2 7 2 Kansas . .. . <3 S 8 1 Kentucky 3 2 1 11 9 4 2 11 6 2 4 9 7 6 101 88 55 7 Nebraska 1 1 1 Nevada 38 23 9 20 1,255 778 623 46 New York 2 North Oakota 40 25 20 2 Ohio 1 1 g 7 4 8 4 3 9 10 4 4 12 13 Texas . . 9 14 3 4 Utah 84 59 38 21 Virginia 8 8 S 4 Wyoming 627 472 '258 147 Total 2.617 1.827 1.263 392

'Applications for permit to drill (APOs) are handed by administrative offices (e.g.. the Eastern States OHico). while lha starts, completions, and abandonments shown in ine three columns following are portrayed by geographic State (e.g.. Arkansas, Florida, Kansas, etc.). Source: Bureau of Land Management Fiscal Year 1990 Quartarly Fluid Mineral Reports.

3S:i Exhibit 4.1 Page 7 of i 74 PUBLIC LAND STATISTICS

TABLE 44.—N0W oil and gas well drilling activities on Federal land, fiscal year 1991

APDs Ntw holts Producible Plugged and Geographic State approved9 started completions abandoned

Alabama , 19 to 16 2 Alaska 4 3 Arizona , 1 1 Arkansas 8 5 9 California 172 174 67 ti Colorado 151 I2J 108 16 Florida 2 ( M C 2 Illinois . 1 4 Kansas 8 8 1 2 11 11 1 s s Michigan 4 3 1 4 Mts.issippi , 19 14 5 11 Montana 80 76 62 6 Nebraska , 2 1 1 Nevada 25 22 3 IS Ntw Mtxico 828 862 633 33 North Oakota ., , 27 26 35 2 Ohio ie 9 39 9 10 1 5 8 a 2 2 12 17 10 t Utah , 158 88 78 Virginia 5 1 1 3 Wyoming 410 291 256 135

Total 1.969 1.783 1.568 260

'Applicationi lor ptrmit to anil (APOs) art handled by administrativa officts (t.g., the Eastern Statts Office), while the starts, completions, and aoanaonmants shown in the three columns following »r» portrayed by geographic Stall (e.g.. Arkansas. Florida. Kansas, tic). Figures in APDs approved column art furnished by trie Statt Olticts. Figurts in the three right-hand columns art Iron) the Quarterly Reports.

Sourct: Bureau o( Land Management Fiscal Year 1991 Quarterly Fluid Mineral Reports.

390 Exhibit 4.2 Page 1 of 2

Well Completions (source: Petroleum Information)

1987 Comnlptions 1988 Cqmntations 1989 Comnlet ions

AL 283 AL 349 AL 523 AZ 4 AZ 1 AZ 3 AR 422 AR 441 AR 337 CA 2,746 CA 2.760 CA 2.027 CO 972 CO 1,120 CO 991 a 8 FL 9 FL 10 GA 3 GA 1 IL 888 ID 1 ID 2 IN 242 IL 1,525 IL 1,312 IA 6 IN 429 IN 328 KS 2,843 IA 1 IA 1 KY 1,133 KS 3,466 KS 3,301 LA 1,800 KY 1,488 KY 1,271 Ml B97 LA 2,517 LA 2,366 MS 288 MO 1 MD 2 MO 11 Ml S43 Ml 672 MT 245 MS 319 MS 351 NE 110 MO 20 MO 13 NV 29 MT 339 MT 388 NM 1,178 NE 219 NE 148 NY 127 NV 14 NV 26 ND 192 937 NM 1,146 OH 1,313 NY 256 NY 179 OK 3,616 NC 1 ND 282 OR 16 ND 213 OH 1.494 PA 893 OH 1,945 OK 4,198 SD 18 OK 4.848 OR 20 TN 74 OR 12 PA 1,079 TX 9,940 PA 1.303 SC 1 UT 93 SC 1 SD 21 VA 33 SD 17 TN 102 WA 3 TN 176 TX 11,731 WV 816 TX 12,891 UT 162 WY 620 UT 141 VA 44 AK 127 VA 38 WA 3 ADFOS 2 WA 1 WV 688 PC 5 WV 879 WY 753 NGM 120 WY 846 AK 154 AK 146 AKFOS 1 TOTAL 31,569 AKFOS 1 PC 6 PC 7 NGM 133 NGM 82 TOTAL 40,062 TOTAL 37,059

Provided by Rocky Mountain Oil & Gas Association Exhibit 4.2 Pace 2 of 2*

1990 Comolstions 1991 ComDlBtlons

AL 1,087 AL 1.121 AZ 5 AZ 3 AR 344 AR 262 CA 2,653 CA 2,399 CO 1,235 CO 1,190 FL 10 FL 7 GA 1 IL 681 IL 821 IN 162 IN 177 KS 3,201 IA 2 KY 1,194 KS 3,434 LA 1,612 KY 1,266 Ml 769 LA 2,070 MS 221 UI 1,044 MO 24 MS 286 MT 285 MO 15 NE 135 MT 336 NV 38 NE 136 NM 1,450 NV 47 NY 50 NM 1,704 NO 220 NY 132 OH 1.175 NO 273 OK 3,315 OH 1.327 OR 10 OK 3,559 PA 496 OR 4 SD 14 PA 602 TN 61 SD 14 TX 10,298 TN 51 UT 223 TX ' 10,390 VA 6 UT 103 WA 1 VA 61 WV 722 WV 808 WY 701 WY 931 AK 173 AK 137 AKFOS 3 AKFOS 3 PC 1 NGM 130 NGM 115

TOTAL 35,198 TOTAL 32,338 31)3 Exhibit 6

Provided by Indcpcndant Petroleum Association of America Exhibit 7

GO

1982 1963 1984 1986 1986 1967 1968 1989 1990 1991 8ourao: OQJ Entrgy DatttaM

Provided In Indcpcndant Petroleum Association of America %^ Exhibit 9 Exhibit 11 I xliilut 12

u^l Exhibit 13

i ;.I..,I i,, v.^.k (lit K- i'.-.i^ Ciuima l ?-^\ ;•• Total wefts 264 v-.'vi'.---; tte C^ora^-Oil Si Gas Gofisei^jiijOfi Commissioit

mmmsmmmmmm Exhibit 15 Stimated Capital Coste for Hypothetical

Production, drilling and completing

Geological/ geophysical research & Production gathering unsuccessful service efforts , research transmission processing

Cumulative production pipeline quality gas 1.5 TCF. Currem daily production 300,000 MCFPD Exhibit 16 GAS GATHERING SYSTEMS Exhibit 17 GAS GATHERING SYSTEM

en

PKLMS r«cmtic$

Exhibit 19

Draft Report: Status of Petroleum Production Industry in California: The Cost of Regulatory Compliance

Submitted to Department of Conservation

by Foster Economics In Association With

California Environmental Resource Associates DNA Associates Resource Decisions

120 Montgomery Street San Francisco CA 94118 415-391-3558

March 26,1993

407 Foster Economics and the study team want to sincere!/ thank and express their appreciation to the members of the Advisory Committee for their assistance throughout the preparation of this report. The information compiled during the data gathering phases of literature search and surveys could not have been accomplished without the efforts of Advisory Committee members.

The contents of this report were developed under Contract No. 2091-025 for the Department of Conservation. Advisory Committee: Petroleum Industry Study

Manuel Alvarez California Energy Commission (CEC) (916)654-3787 Desmond Bain U.S. Forest Service (415)705-2543 Paul Blais California Environmental Protection Agency (916)324-7584 (Cal-EPA) Susan Brown CEC (916)654-4873 Michael Byrne California Department of Conservation (DOC) (916)322-1080 Jim Campion DOC, Division of Oil and Gas (DOG) (916)323-1779 Kevin Chom CEC (916)654-3787 Dick Crippen Conservation Committee of California Oil at (213)680-9010 Gas Producers (CCCOGP) Paul Dunlevy U.S. Bureau of Land Management (BLM) (916)978-4735 Jack Geek Department of Fish « Game - Oil Spill (916)323-4664 Prevention and Response (OSPR) Bill Guerard DOG (916)324-1444 Ken Henderson DOG (916)323-1777 Thomas Hunt California Independent Petroleum Association (916)447-1177 (CIPA) Nancy Johnson U.S. Department of Energy (202)586-6458 Michael Kahoe Cal-EPA (916)322-5844 Stowe Killingsworch CIPA (805)631-2919 Dan Kramer CIPA (916)447-1177 ]ason Marshall DOC (916)322-1080 Leroy Mohorich BLM- (916)978-4735 Paul Mounc California State Lands Commission (310)590-5205 Bill Northrop Independent Oil Producers Agency (IOPA) (916)442-7095 Chuck Raysbrook OSPR (916)445-9326 Cathy Reheis Western States Petroleum Association (WSPA) (805)321-0884 Robert Sands OSPR (916)324-6261 Mike Wang WSPA (818)543-5349 Gary Yee California Air Resources Board (916)327-5986 Darryl Young Sierra Club of California (916)557-1100 TABLE OF CONTENTS

Advisory Committee

Section t: Executive Summary and Recommendations

1.0 Introduction 1-1 1.1 Summary of Findings 1-2 1.1.1 An Industry in Decline 1-2 1.1.2 Employment and State Revenues at Stake 1-3 1.1.3 Regulatory Compliance Costs 1-4 1.1.4 Key Elements of Regional Cost Differences 1-9 1.1.5 Agency Overlaps Which Cause Inefficiency 1-10 1.2 Recommendations 1-12 1.2.1 Produced Water Management 1-12 1.2.2 Hazardous Waste 1-14 1.2.3 Threatened and Endangered Species 1-15 1.2.4 State Tidelands 1-16 1.2.5 Air Quality 1-17 1.2.6 Oil Spill 1-18 1.2.7 Management Audit 1-19 1.2.8 Recommended Downstream Study 1-19

Section 2: The Status of the California Petroleum Industry

2.0 Purpose 2-1 2.1 Overview of California Petroleum Industry 2-2 2.1.1 Statewide Oil and Gas Production Trends 2-4 2.1.2 Regional Production Trends 2-13 TABLE OF CONTENTS, continued

2.1.3 Oil and Gas Prices in California and the U.S. 2-25 2.1.4 Regional Costs and Profitability of Producing Crude Oil 2-29 2.2 The Economic Significance of the Industry: A 1990 Snapshot 2-35 2.2.1 Employment 2-39 2.2.2 Payroll 2-45 2.2.3 Taxes and Revenues 2-47 2.2.4 Linkages To Other Sectors 2-57

Section 3: Environmental Laws and Regulations Governing Oil and Gas Exploration and Production

3.0 Purpose 3-1 3.1 Agencies Regulating Oil and Gas Production 3-2 3.1.1 Federal Agencies 3-3 3.1.2 State Agencies 3-4 3.1.3 Local Agencies 3-5 3.2 Oil and Gas Producing Environmental Functional Areas 3-6 3.3 Laws and Regulations Governing Functional Areas 3-7 3.4 Significant Laws and Regulations by Functional Area 3-11 3.4.1 Produced Water Management 3-12 3.4.2 Waste Management 3-14 3.4.3 Emergency Preparedness and Response 3-17 3.4.4 Land Access and Land-Use Permits 3-20 3.4.5 Air Quality Control 3-22 3.4.6 Toxic Air Contaminants 3-26 3.4.7 Hazardous Material Handling and Storage 3-28 TABLE OF CONTENTS, continued

3.4.8 Transportation and Pipelines 3-30 3.4.9 Oil Spill Prevention and Response 3-31

Section 4: Cost of Environmental Laws and Regulations Governing Oil and Gas Exploration and Production

4.0 Purpose 4-1 4.1 Definition of Costs 4-2 4.1.1 Costs Included 4-2 4.1.2 Costs Not Included 4-3 4.2 Reported Costs of Regulation 4-4 4.2.1 Reported Cost Summaries 4-4 4.2.2 Statewide Cost Estimates 4-7 4.3 Costs by Functional Area 4-11 4.3.1 Costs: Produced Water Management 4-11 4.3.2 Costs: Waste Management 4-13 4.3.3 Costs: Hazardous Material Handling, Storage, Emergency Preparedness and Response (Combined) 4-15 4.3.4 Costs: Land Access and Land-Use Permits 4-17 4.3.5 Costs: Air Quality Control, Including Toxic Air and Air Emission Fees & Taxes 4-19 4.3.6 Costs: Environmental Fees and Taxes 4-21 4.3.7 Costs: Transportation and Pipelines 4-23 4.3.8 Costs: Oil Spill Prevention and Response 4-25 4.4 Costs by Regions 4-27 4.4.1 Regional Cost Comparison 4-27 4.4.2 Causes of Regional Cost Differences 4-29

412 TABLE OF CONTENTS, continued

4.5 Regional Environmental Costs Compared to Lifting Costs 4-49 4.6 Costs by Agency 4-50 4.7 Industry Comments 4-52

Section 5: Benefit/Cost Analysis of Environmental Laws and Regulations

5.0 Purpose 5-1 5.1 The Role of Benefit/Cost Analysis in Environmental Regulatory Policy 5-2 5.1.1 What Is Benefit/Cost Analysis and Why Is It Important? 5-2 5.1.2 Introduction to Environmental Economic Analysis 5-7 5.1.3 What are the Properties of an Ideal Environmental Regulation? 5-11 5.1.4 A Common-Sense Solution to Missing Benefit Estimates 5-19 5.2 Air Quality Regulations 5-20 5.2.1 Criteria Pollutants 5-20 5.2.2 Regional Benefit/Cost Analysis of Ozone Control 5-30 5.2.3 Air Toxics 5-33 5.3 Water Quality Regulations 5-35 5.3.1 Produced Water Management Dominates Oil and Gas Producers' Water Management 5-35 Efforts

IV TABLE OF CONTENTS, continued

5.3.2 Cost-Effectiveness Comparison of Disposal Methods 5-39 5.3.3 Benefits of Produced Water Management Depends on Toxicity 5-40 5.3.4 Regional Considerations 5-41 5.4 Non-Emission Environmental Regulations 5-43 5.4.1 What are Non-Emission Regulations? 5-43 5.4.2 Benefits of Non-Emission Regulations 5-46 5.4.3 Regional Considerations in Non-Emission Regulations 5-54 5.5 Administrative Costs of Environmental Agencies 5-57 5.5.1 Why Are Administrative Costs Important? 5-57 5.5.2 Quantitative Measurements of Administrative Efficiency 5-58 5.5.3 Administrative Efficiency Comparison 5-59 5.6 Conclusions and Recommendations Regarding "Problem" Regulations 5-62 5.6.1 General Conclusions 5-63 5.6.2 Air Quality Regulations Benefits 5-65 5.6.3 Water Quality Regulations Benefits 5-65 5.6.4 Hazardous Waste Disposal 3enefits 5-66 5.6.5 Hazardous Material SC Emergency Preparedness Benefits 5-66 5.6.6 Non-Emission Regulations Benefits 5-67

v.i TABLE OF CONTENTS, continued

Section 6: Legal and Regulatory Overlaps Resulting From Environmental Laws and Regulations Governing OH and Gas Exploration and Production

6.0 Purpose 6-1 6.1 Overlaps, Duplication, and Conflicts 6-2 6.1.1 Produced Water Management 6-4 6.1.2 Waste Management 6-8 6.1.3 Hazardous Material Emergency Preparedness and Response 6-12 6.1.4 Land Access and Land-Use Permits 6-14 6.1.5 Air Quality 6-17

6.1.6 Oil Spill Prevention and Response 6-20

Appendix A Methodology for Regulatory Review and Cost Data A-1

Appendix B Methodology for Estimating State Revenues and Taxes B-l

Bibliography Bib-1

VI 3/5 LIST OF TABLES

1.1 Regulatory Costs of Compliance Compared to Total Lifting Costs 1-7 1.2 Coastal and Valley Regulatory Compliance Costs 1-8 1.3 Major Determinants of Regional Regulatory Compliance Cost Differences 1 -8

2.1 California Crude Oil Receipts at California Refineries by Source of Supply 2-11 2.2 Crude OH Production by Region 2-14 2.3 Producing Oil £Z Associated Gas Wells 2-17 2.4 Regional Oil Production Trends 2-20 2.5 Net Gas Production by Region 2-2] 2.6 Producing Dry Gas Wells 2-22 2.7 Ranking of Californfa Oil and Gas Producing Counties by Value of 1990 Production 2-24 2.8 California Regional Crude Prices 2-27 2.9 Regional Distribution of Light/Heavy Crude Oil Production 2-34 2.10 Oil sc Gas Production Employment and Payroll by County 2-40 2.11 Oil fit Gas Production Direct, Indirect and Induced Employment and Payroll by County 2-44 2.12 Summary of State 2nd Local Revenue Impacts of California Oil sc Gas Production 2-48 2.13 County Revenue Sources: Fiscal Year 1990-1991 2-49 2.14 Sales and Use Taxes Paid bw Petroleum Production Sectors 2-56

VII LIST OF TABLES, continued

2.15 California Purchases by Petroleum Production Sectors 2-59

3.1 Environmental Health and Safety Laws and Regulations 3-8

4.1 Summary of Reported Cost Data 4-5 4.1a State Total (Excl. Sacramento) Cost Summary 4-8 4.1b Statewide (Exci. Sacramento) Cost Summary • BOE 4-9 4.2a San joaquin Total Cost Summary 4-31 4.2b San )oaquin Cost Summary - BOE 4-32 4.3a Ventura Total Cost Summary 4-35 4.3b Ventura Cost Summary - BOE 4-36 4.4a Long Beach Total Cost Summary 4-38 4.4b Long Beach Cost Summary - BOE 4-39 4.5a Santa Maria Total Cost Summary 4-42 4.5b Santa Maria Cost Summary - BOE 4-43 4.6a Sacramento Total Cost Summary 4-46 4.6b Sacramento Cost Summary - BOE 4-47

5.1 Air Emission Trends for Oil St Gas Producing Areas 5-21 5.2 Air Emission Trends for Oil fit Gas Producing Areas 5-22 5.3 Population, Area, Ozone Emissions by Oil sc Gas Producers, and Cost per Pound Reduction 5-32 5.4 Regional Produced Water to Oil Ratios 5-36 5.5 Produced Water Disposition by Oil and Gas Producers 5-37 5.6 Produced and Injected Waters by Region 5-42 5.7 Costs of Compliance with Non-Emission Environmental Regulations 5-47

VIII

4 - '1 =2.'- i LIST OF TABLES, continued

5.8 Distribution of Non-Emission Regulatory Costs by Oil fit Gas Region 5-55 5.9 Quantitative Comparison of DOG and SIC Administrative Efficiency 5-61

IX LIST OF CHARTS

1.1 Statewide Compliance Costs/Environmental Functional Area 1-5 1.2 Environmental Cost/Oil and Gas Study Regions 1 -6

2.1 California Oil SC Condensate Production 2-5 2.2 Light sc Heavy Oil Production Trends 2-6 2.3 Number of Producing Oil sc Associated Gas Wells in California 2-7 2.4 California Net Gas 2-8 2.5 Number of Producing Dry Gas Wells in California 2-9 2.6 Alaska Crude Production Forecast 2-12 2.7 Regional Crude Oil Production 2-16 2.8 Proven Oil Reserves by Region 2-19 2.9 Wellhead Prices for Oil 2-26 2.10 California City Gate Prices for Gas 2-28 2.11 Average Regional Lifting Costs for California Crudes 2-30 2.12 Prices and Average Lifting Costs for California Crudes 2-33 2.13 California Petroleum Employment Trends 2-36 2.14 California Employment Changes for Selected Industries 2-37 2.15 Changes in California Employment 2-38 2.16 In-State Purchases by the California Petroleum Industry 2-58

4.1 Statewide Costs: Environmental Functional Area 4-10 4.2 Costs: Produced Water Management 4-12 LIST OF CHARTS, continued

4.3 Costs: Waste Management 4-14 4.4 Costs: Hazardous Material Handling & Emergency Preparedness 4-16 4.5 Costs: Land-Use SC CEQA 4-18 4.6 Costs: Air Regulations 4-20 4.7 Costs: Fees SC Taxes 4-22 4.8 Costs: Transportation & Pipelines 4-24 4.9 Costs: Oil Spill Prevention ar Response 4-26 4.10 Costs: By Oil SC Gas Study Regions 4-28 4.11 San Joaquin Environmental Functional Area Costs 4-30 4.12 Ventura Environmental Functional Area Costs 4-34 4.13 Long Beach Environmental Functional Area Costs 4-40 4.14 Santa Maria Environmental Functional Area Costs 4-44 4.15 Sacramento Environmental Functional Area Costs 4-48 4.16 Environmental Costs: By Agency 4-51

5.1 Optimal Level of Environmentallmprovement 5-14 5.2 Trend of Stationary Source Emissions for Oil and Gas Production as a Percent of California Total 5-24

xi 420 LIST OF EXHIBITS

A-1 Oil and Gas District Boundaries of DOG A-4 A-2 List of Agency Contacts A-6 A-3 List of Industry Contacts A-7 A-4 Sample Letter Sent to Agency Representatives A-9 A-5 Sample Letter Sent to industry Representatives A-11 A-6 Cost Survey Matrix for the Long Beach and Tidelands A-13 Region A-7 Cost Survey Letter and Instructions Sent to Industry A-25 A-8 Long Beach Reported Costs A-2 9 A-9 Sacramento Reported Costs A-31 A-10 San ]oaquin Reported Costs A-3 3 A-11 Santa Maria Reported Costs A-35 A-12 Ventura Reported Costs A-3 7

B-1 State Revenue Sources from Oil and Gas Producers B-5 B-2 County Revenue Sources B-6 B-3 Estimate of California Purchases by Petroleum Production Sectors B-12

XII DRAFT REPORT: STATUS OF PETROLEUM PRODUCTION INDUSTRY IN CALIFORNIA: THE COST OF REGULATORY COMPLIANCE

SECTION!: EXECUTIVE SUMMARY AND RECOMMENDATIONS

1.0 Introduction

Oil and gas are integral building blocks of the economic infrastructure of the United States and California. California relies on petroleum and natural gas for 88 percent of its energy needs, even more than the U.S. average. The production sector of the industry in California has been in decline since 1985 with an attendant loss of jobs and state revenues. This large and important industry is sustaining declines similar to those experienced in the Manufacturing sector -- reduced output and employment. Are the costs of regulations on California oil and gas producers part of the cause of the downturn?

Foster Economics was retained by the Department of Conservation (DOC) to examine the regulatory compliance costs on the oil and gas producing industry, to answer the above question and to make recommendations. Six tasks were specified by the contract.

1. identify the impacts of the oil and gas production industry on state and local employment and public revenues. (Section 2.)

2. Compile a list of environmental and other laws and regulations that affect the oil and gas production industry. (Section 3.)

3. Estimate costs associated with complying with regulations and summarize the cost impacts of these factors on the oil and gas production industry of California. (Section 4.)

i-i 4. Identify laws and regulations which have a high cost/benefit ratio (low benefit/cost ratio) and pose excessive burden on the oil and gas production industry. (Section 5.)

5. Identify regulatory overlaps among agencies and regulations. (Section 6.)

6. Develop a corrective action plan to lessen the regulatory cost burden to the industry without compromising environmental protection. (Section 1.2)

The study team undertook a survey of oil and gas producers and agencies both to confirm environmental regulations and determine their costs. The survey was conducted over the six oil and gas producing districts of California The data are aggregated to five regions:

• San ]oaquin (Coalinga + Bakersfield) • Long Beach (Los Angeles and Orange County including Tidelands) • Ventura • Santa Maria • Sacramento.

The results of that survey are the backbone of this report. Appendix A explains how the survey was conducted and the data processed.

1.1 Summary of Findings

1.1.1 An Industry In Decline

California crude oil and natural gas production have declined precipitously since peaks in 1984 and 1985.

• Natural gas production down 31 percent. • Crude oil production down 23 percent.

1-2 Operating wells and new wells drilled in 1992 are at their lowest levels in recent history. The 1991 - 1992 decline in producing oil wells is the steepest single year drop in the last ten years.

Numerous factors encouraged U.S. companies to pursue exploration abroad in recent years. These include increased costs of operating within the United States and stringent environmental regulations. Declining wellhead prices since 1985 have acted as an inducement to search worldwide for the most cost-effective exploration and development opportunities. Clearly, these are not in some of California's historic producing regions -- notably, the coastal districts, where production has declined significantly more than the U.S. average since 1985. San Joaquin Valley production, which accounts for 75 percent of the state's crude oil production, has held up better than the rest of the U. S.

Declining statewide production means:

Increasing reliance on foreign crude imports; Increasing strategic vulnerability; Decreasing California employment; Decreasing California payroll; and Declining government revenues.

1.1.2 Employment and State Revenues at Stake

The oil and gas production industry accounted for a $1.45 billion direct payroll in 1990. At $45,000 average annual salary, this is a highly skilled, highly paid work force. Linkages between this industry and the rest of the state created a total payroll related to the industry of $2.75 billion. Direct employment in the oil and gas production industry had dropped 11 percent from 1990 levels by 1992 ; this is a loss of nearly $ 160 million in personal income to California with an attendant loss of personal income tax revenues.

1-3 Total tax, fee and royalty payments to state and local governments totalled over $600 million in 1990 - over 10 percent of wellhead value of production. The decline in production, prices and employment since 1990 has caused payments to state and local governments to decline substantially -- approximately $ 100 million.

1.1.5 Regulatory Compliance Costs

At least thirty-four federal, state nd local agencies managed dozens of regulatory requirements identified in Section 3 of the report. Compliance with these regulations imposed costs of $326 million on the industry for 1991. Chart 1.1 shows that compliance with regulations imposed by air districts caused nearly $ 180 million or these costs. Produced water management costs imposed by DOC, SWRCB, RWQCB and local agency requirements add-up to the second largest costs. Local agency imposed costs (not shown on Chart 1.1) to comply with water and waste disposal, spill reporting and land-use permits totalled $44 million.

These costs were not distributed uniformly across California production districts. Total compliance costs ranged from $0.55 per barrel of oil equivalent (BOE) in the San Joaquin producing area to $2.39 per BOE in Long Beach as shown on Chart 1.2. There is such a difference in regulatory compliance costs among regions that the statewide average of $0.92 is misleading. Table 1.1 compares these costs to the total lifting cost (variable production costs) estimated by Conservation Committee of California Oil sr. Gas Producers (CCCOGP) and to recent wellhead prices.

The high regulatory costs of Santa Maria production, together with the transportation discount charged against its production value, caused lifting costs to be greater than wellhead prices in that region. Ventura production values covered lifting costs at recent prices, but left little surplus to cover fixed costs and profits. Only San Joaquin production costs were sufficiently low to conclude that production values clearly covered lifting costs, other fixed costs, overhead and profit.

1-4 Chart 1.2 Environmental Cost/Oil and Gas Study Regions

Dollars Per DOE 2.5

1.5

0.5

0 State (excl. San Joaquin Ventura, Santa Maria Long Beach, Sacramento) Tidelands Tidelands Chart 1.1 Statewide Compliance Costs/Environmental Functional Area

Air Quality Regs.

Produced Water Mgmt.

Waste Management

Handling & Emergency Preparation

Oil Spill Prep.

Land Use & CEQA

Fees & Taxes Transport & Pipelines 0 50 100 150 200 Million Dollars Per Year Total Costs (cxcl. Sacramento): $326 Million Per Year Table 1.1 Regulatory Compliance Costs Compared to Total Lifting Costs REGION Regulatory District %Of Total Well Compliance Production Lifting Lifting Head Cost (MBOE/D) Cost Cost Price ($/BOE) ($/BOE) ($/BOE) Santa Maria $2.05 34 18% $11.22 $10.75 Long Beach $2.39 136 27% $8.99 $12.00 sc Tidelands Ventura ex $1.73 52 15% $11.87 $12.80 Tideiands San Joaquin $0.55 746 9% $5.94 $11.75

Only part of the much lower cost per barrel of regulatory compliance in San Joaquin represents economies of scale. Although coastal production amounted to only 30 percent of San ]oaquin Valley production, the total cost of regulations in the coastal areas exceeded the regulatory costs in the valley, as shown on Table 1.2. The cost of regulatory compliance for coastal producers is nearly four times higher than valley producers. The regulatory cost differential between San Joaquin and coastal areas is partly the cause of the distressed state of the industry in the coastal and tideland areas of Southern California.

1-7

i- J Table 1.2 Coastal and Valley Regulatory Compliance Costs Production Total Regulatory Cost Cost BOE ($ Million) per MBD BOE Coastal 222 177 $2.18

Valley 746 150 $0.55

Table 1.3 shows that the range in district air regulation costs explains part of the difference between the low cost San Joaquin region and the high cost coastal regions. The largest determinant of Long Beach being the highest cost region is compliance with SCAQMD's air regulations and various waste management regulations. The largest determinants of Santa Maria's high costs are air regulations and local land-use regulations. Santa Maria had the highest air fees in the study regions. San joaquin had few land use expenses in 1991 mostly because of the small amount of new development activity in that year.

Table 1.3 Major Determinants of Regional Regulatory Compliance Cost Differences $ per BOE REGION Air Regs Land Water Waste Other Total /Fees Use/ Mgmt. Mgmt. Cost CEQA Santa Maria $0.62/0.33 $0.63 $0.23 $0.07 0.17 $2.05 Long Beach St $0.92/0.17 $0.06 $0.24 $0;47 0.53 $2.39 Tideiands Ventura ac $0.64/0.03 $0.12 $0.26 $0.13 0.55 $1.73 Tideiands San joaquin $0.36/0.01 nil in $0.08 $0.03 0.07 $0.55 1991

1-8 1.1.4 Key Elements of Regional Cost Differences

Table 1.3 suggests that, besides the large air district imposed cost differences, regulatory costs related to land use permits, produced water and Waste management are key elements of the regional cost differences.

• Long Beach's high cost production is located in the SCAQMD non-attainment area which has the strictest enforcement of air regulations. For instance, Long Beach requires oil production vent controls, sump controls and storage tank controls that are not required in San Joaquin.

• San Joaquin's very low cost per BOE reflects, in part, economies of scale; Santa Maria's high cost per BOE reflects, in part, a declining industry with relatively few wells to sustain the cost of environmental restrictions imposed locally.

• Santa Maria imposed the largest fee on air emissions. Under current laws local agencies can impose fees without any state oversight.

• The Santa Maria CEQA process costs are causing relatively high costs compared to these costs in the other regions.

• Produced water management reflects very high costs of required PublicaNy Owned Treatment Works (POTW) disposal in Long Beach and Ventura. (The Santa Maria produced water cost estimates include oil spill response costs misreported within the category.) Managing produced water according to DTSC and RWQCB rules imposes high-cost POTW disposal. Less than 2 percent of produced water statewide is disposed of to POTWs; but this disposal requirement accounted for $18.5 million - 42 percent of the $44 million produced water management cost statewide.

1-9 • The very high waste management costs in Long Beach reflect SCAQMD's rule regulating emissions from oily dirt and DTSC and f

• Most of the difference in "other" costs on Table 1.3 is due to oil spill response costs. These are $0.28 and $0.32 in Ventura and Long Beach, and less than $0.01 in San joaquin. Santa Maria data are mis-reported and include oil spill costs within produced water management costs.

f. 1.5 Agency Overlaps Which Cause Inefficiency

Section 6 of this report shows that there are a number of key conflicts in regulatory management that impose unnecessary regulatory complexity to oil and gas producers. These are:

Issue Conflicting Agency Rules

Oily Soil/Hazardous Waste DTSC/ DOC/ RWQCB Oil Spill DOC/ SLC/ DFG Tideiands Production DOC and SLC Produced Water DOC/ DTSC/ RWQCB Emergency Preparedness EPA/ DOT/ DOC/ DFG/ SLC/ etc. Endangered Species DFG/ USFstWS/ local agencies.

Incrementally-develcped regulations by multiple agencies have led to overlaps in authority as agencies expanded their sphere of influence to oversee operations believed to be within their responsibility. As a result, layers of regulations now delay approvals for drilling projects and explain part of the high regulatory costs shown in Section 4.

Besides these overlapping agency problems, California oil producers are put at a financial disadvantage to producers elsewhere by California's unique regulations, more stringent than their federal counterparts.

1-10 • CEQA is a unique set of regulations more stringent than NEPA, which are intended to preserve the beauty of the Golden State. The net effect of CEQA on the producing industry is to increase the complexity of receiving a permit. This reduces the number of projects to produce oil and inject water and leads to higher costs and lost opportunities.

• DTSC's hazardous waste management rules include substances not considered hazardous under federal RCRA rules. This imposes added costs on California oil producers and added burdens to California's limited land fill capacity. Long Beach's $0.47 per BOE cost for oily soil management is a clear example.

• DTSC, SWRCB and RWQCB rules cause some California producers to dispose of produced water to POTWs at very high costs. Long Beach's and Ventura's $0.10 per BOE cost for POTW disposal are clear examples.

• Air quality rules are set by local authorities to conform to the federal and state Clean Air Acts. Local authorities only have control of stationary source emissions. The SCAQMD region has the most difficult task of any in the nation in its efforts to bring its air quality into federal compliance. The Long Beach oil and gas producing industry is now paying nearly $ 1.10 per BOE to conform to SCAQMD's requirements.

The costs of the above local regulations and the complexity imposed by multiple layers of enforcement create disincentives to operate in the state. This will reduce the ultimate recovery of California oil in place. Until either petroleum prices increase or regulatory costs decrease, the California production industry will continue to decline faster than the national average even though the ratio of California's discovered reserves to production exceeds the U.S. average by 35 percent. The oil is here, but declining production shows that the incentives to produce it are not here.

i-n California has no requirement that benefit/cost analysis be used to justify regulations. A review of agencies within this project revealed that only the South Coast Air Quality Management District had conducted any studies of the benefits of their regulations. Benefit/cost analysis can be a very useful tool for refining environmental policies. California lags the national trend of applying benefit measurement techniques to environmental regulatory policies.

The recommendations that follow address solutions to these problem regulations.

1.2 Recommendations

The Governor's '93-94 budget suggests that a substantial reorganization of government functions will take place in the coming fiscal year. To act as a guide in such a process, this report formulates a number of recommendations to streamline California oil and gas production regulations. These recommendations are aimed at:

• Reducing the cost of regulatory compliance to enable the California producers to compete for world marketshare;

• Reducing the cost of California state government to reflect the lower state budgets;

• Requiring more evidence that environmental ant' health benefits exceed the costs of regulations.

1.2.1 Produced Water Management

The Department of Conservation should continue cooperative efforts with the U. S. Environmental Protection Agency, and the Ground Water Protection Council to ensure continued Division of Oil and Gas regulatory primacy of Class II injection wells.

1-12 The existing regulatory primacy maintained by DOG over Class II injection wells is the least costly and most efficient means of administering this activity. The DOG's ability to regulate these wells in a safe and environmentally sound manner has been demonstrated by program review and study by the Environmental Protection Agency.

A management strategy should be developed by DOC and affected interests for determining the highest value and besr use of produced water.

Discharging produced water into local sewers is expensive to the oil and gas industry and potentially wasteful (Chart 4.1). Further, injection and surface disposal of produced water may not be its most beneficial use. In some cases produced water may be of sufficient quality for other, more valuable uses. Alternative disposal options will vary by region, and, therefore should be the subject of discussion between the DOG, Regional Water Quality Control Boards, local sanitation districts, the affected oil and gas producers, and primary water users.

The permit process for injection wells should be streamlined.

Currently, the process for obtaining an injection well permit entails a DOG permit plus other local land use permits which are costly and time consuming. Injection of produced water is often the least costly and most efficient means of produced water disposal to the oil and gas industry. Conflicts between agencies discussed in Section 6 should be resolved so that permits to drill injection wells can be streamlined. DOG should lead state agency efforts to assure multi-agency permitting.

1-13

434 1.2.2 Hazardous Waste

The Department of Conservation and the Department of Toxic Substances Control should develop a management agreement to transfer inspection and reporting requirements of the DTSC to the Department of Conservation.

Produced water used for enhanced oil recovery often requires pretreatment. Many facilities constructed for the purpose of treating water fall under the purview of the Department of Toxic Substances Control (new Permit-by- Rule (PBR) program) and are subject to annual fee, inspection and reporting requirements. Similarly, oily soil determined to be hazardous under California law is subject to the purview of the DTSC. The DOC regulates most other aspects of enhanced recovery and oil field waste operations. The transfer of inspection and reporting requirements to the DOC has the potential of achieving cost savings for the state and the oil and gas industry. The Governor's 1993/94 Budget for DTSC is $ 136 million. This reflect'* 57 new Person Year's (PY's) to implement PBR. In addition, it includes 303 PY for site mitigation oversight. By transferring PBR and site mitigation oversight at oil and gas operations to DOC savings in the DTSC PY needs could be realized.

The recycling of non-hazardous Resource Conservation and Recovery Act (RCRA) waste should be encouraged.

Typically tank bottom waste and drilling muds are classified as non-hazardous but, are required to be disposed of in Class I landfills. The cost of disposing waste in these facilities varies, but can be as high as $100 per ton. In the past, the oil industry has used much of this material in the oil fields as low cost road bed. Currently, the quantity of such material exceeds the ability for industry's internal use and is being

1-14 landfilled. This material can be transformed into a road bed/dust suppressant at substantially less cost than the cost of landfilling. The net effect is optimum use of the material and extending the useful life of Class 1 landfills.

1.2.3 Threatened and Endangered Species

The Department of Conservation should coordinate efforts between the U.S. Fish and Wildlife Service and the California Department of Fish and Game to ensure the development of Habitat Conservation Plans in oil production and exploration areas.

Habitat Conservation Plans do not exist in the primary oil production and exploration areas of the state. The result is a lack of certainty about the cost of conducting botanical and biological studies and ultimately the cost of mitigation. Habitat Conservation Plans define the goals of the responsible agencies of government for protecting species, thereby inserting a level of predictability into the oil and gas industry's decision-making process.

The appropriate agencies of the state anu federal government should be requested to conduct management review of U.S. Fish and Wildlife Service and California Department of Fish and Game processes relative to the Issuance of Management Take Permits.

The petroleum industry's experience with the permit process time frame of both agencies suggests either a lack of staff resources and/or confused priorities. Even when developers have funded the preparation of biological and botanical studies or the preparation of Habitat Conservation Plans, the time frame for review and approval has been lengthy and unpredictable.

1-15 Authorizing legislation should be enacted to allow the State to coordinate "Development Agreements."

Under current law, local agencies may initiate Development Agreements. These agreements are used by project proponents and local agencies to assemble the responsible agencies of the state, local, and federal government to produce an agreement for development. These agreements can be developed concurrently with CEQA/NEPA processes. Conceivably, such an agreement could be applied in those oil production areas where new development or exploration might occur and could cover the necessary conditions for permit issuance by the affected governmental agencies. The Department of Conservation as an agency of state government is in the best position to coordinate such agreements.

1.2.4 State Tidelands

Management of the development and operation of the state tidelands oil production should be transferred to the Division of Oil and Gas within the Department of Conservation.

Under current law the Department of Conservation and the State Lands Commission both have responsibility for supervising specific aspects of the drilling, operation, and maintenance of oil production within the state's tidelands. The staff of each organization possess the same professional expertise and perform similar regulatory functions.

As detailed in Section 5.5, the State Lands Commission expends approximately $6.3 million annually to regulate production of 23.2 million barrels of oil. The Division of Oil and Gas expends $9.1 million annually to regulate 319 million barrels of production which includes the 23.2 million

1-16

107 barrels of production regulated by the State Lands Commission. Included in the responsibilities of the State Lands Commission is the oversight and management of the East Wilmington Field which is primarily administered and managed by the City of Long Beach.

The State Lands Commission's functions of reservoir management, study, prediction, production, well regulation, and facility regulation could be transferred to the Division of Oi! and Gas to eliminate duplication and achieve substantial savings to the State. Oversight of leasing and lease management could continue to be accomplished by the State Lands Commission. This would allow the State Lands Commission to continue to assure protection of the environment in East Wilmington. The City of Long Beach would continue as the primary administrator of the East Wilmington Field.

1.2.5 Air Quality

The appropriate air quality authorities should consider applying benefit/cost analysis to existing and future standards as they relate to criteria pollution controls for heavy oil production.

As detailed in Section 5, the magnitude of benefits of criteria pollution controls are related directly to nearby population density. Section 5 raises serious questions about the benefit/cost ratio of exiting controls as they apply to oil and gas production in all AQMD's studied other than, perhaps, the South Coast.

Even though air quality authorities typicalty conduct cost- effectiveness analysis, this report concludes that cost- effectiveness analysis should not be the only measure applied to air quality regulation. The Department of

1-17 Conservation should coordinate efforts with the appropriate air quality authorities to assess the potential for implementing an analysis of benefits and costs of further air emission reductions.

Given the magnitude of costs incurred by the oil and gas industry in meeting air quality compliance obligations, the implementation of a benefit/cost analysis in conjunction with the current cost-effectiveness analysis will result in the development of better scientific justification for controls and regulations. We believe the goal of providing health based air quality standards, at the least cost to the affected industries, warrants the coupling of the two methods of analysis.

1.2.6 OH Spill

Oil Spill Programs should be consolidated within the Department of Fish and Game and the Department of Conservation.

Industry compliance with the governmental mandates, as they relate to oil spills, is a complex task involving multiple agencies of state, federal, and local government. .At the State level the principal agencies involved are the Department of Conservation, Department of Fish and Game, and the State Lands Commission. We believe the consolidation of existing state agency functional responsibilities within DOG and the Department of Fish and Game's OSPR program will produce a more coherent and streamlined oversight program.

Consolidating the activities of facility siting and permitting programs into the DOG and facility and transportation vessel monitoring to OSPR would clarify regulatory responsibility, improve regulatory accountability, and provide consistency of review.

1-18 1.2.7 Management Audit

The Department of Conservation should conduct a program audit of its Division of OH and Gas.

The Division of Oil and Gas within the Department of Conservation is an integral component in the regulation of the oii and gas industry. Moreover, the annual assessment of the oil and gas industry to support the Division's regulatory programs is a cost to that industry.

The Department of Conservation has recently initiated a strategic planning process in an effort to prioritize programmatic efforts and maximize budgetary efficiencies.

Consistent with that effort, it is prudent and appropriate for the Department to conduct an internal (management) audit of the Division of Oil and Gas program management practices.

1.2.8 Recommended Downstream Study

The Department of Conservation, California Energy Commission and Federal Department of Energy should cooperatively conduct a similar study on the economic status of the Downstream oil and gas industry.

Clearly the Upstream focus of this study covers only one segment of economic status of California's oil and gas industry. While this report's upstream assessment of issues is an important factor to the overall health of the industry, it should not be viewed as a complete picture.

The importance of the oil and gas industry to the California economy, as detailed in Section 2, emphasizes the need for a complete economic assessment. The overwhelming costs of compliance with the federal Clean Air Act Amendments and CARB's even stricter dictates have created, perhaps, the

1-19 largest challenge the refining sector has ever had to deal with. A Downstream study would be particularly well-timed in 1993 in view of status of work in-progress to comply with CARB's Phase II rules.

1-20 Exhibit 20

KEY FEDERAL STATUTES AFFECTING OIL AND GAS LEASING AND ACCESS FOR EXPLORATION AND PRODUCTION

Mineral Leasing Act

It provides the authority of the Secretary of the Interior to issue oil and gas leases and governs the leasing of federal lands, including the authority of the surface management agency and the Bureau of Land Management to apply environmental stipulations to leases.

Endan°ered Species Act

It provides procedures for the conservation, protection, restoration and propagation of threatened and endangered plant and animal species.

Federal Land Policy and Management Act

It provides the fundamental philosophical direction to the Department of the Interior for the management of federal lands, including the inventory of such lands for possible wilderness designation, areas of critical environmental concern, rights-of-way, and land management planning. Underlying principles are multiple use and sustained yield.

National Historic Preservation Act

It establishes a program for the preservation of significant historical and cultural properties, through a national register of historic sites.

National Environmental Policy Act

It requires the federal government to establish a procedure for analysis of environmental impacts of a proposed federal action on the quality of the human environment, including historic, cultural, economic and social impacts.

National Forest Management Act

It directs the U.S. Forest Service in the management of its lands, including forest planning for multiple use management.

Wild and Scenic Rivers Act

It establishes a procedure foi the designation and protection of wild and scenic rivers.

Provided by Rocky Mountain Oil & Gas Association AppendixC Selected List of Federal Legislation Affecting Land Use Planning, Management, and Control

(Taken tcoa GAO staff study, "Land Use Planning, Management, and Control: Issues and Problems," July 1977) 1. Mining Law of 1872 2. Pickett Act of 1910 (authorizes land withdrawals). J. Mineral Land Leasing Act of 1920. 4. Federal Power Act of 1920. 5. Clarke-HcN'ary Act of 1924 (production of tree seeds and seedlings). 6. Snyder Act of 1924 (develop Indians' human and natural resources). 7. Indian Reorganization Act of 1934 (same as no. 6). 8. Taylor Grazing Act of 1934. 9. Bankhead-Jones Farm Tenant Act of 1937. 10. Federal-Aid in Wildlife Restoration Act of 1937. 11. Federal Property and Administrative Services Act of 1949. 12. Housing Act of 1954. 13. Fish and Wildlife Act of 1956. }4 National Environmental Policy Act of 1959. 15. Multiple Use—Sustained Yield Act of 1960. 16. Bureau of Outdoor Recreation Act of 1952. 17. National Wilderness Preservation System Act of 1964. 16. Urban Mass Transportation Act of 1964. 19. Water Resources Act of 1965. 20. Solid Waste Disposal Act of 1965. 21. Public Works and Economic Development Act of 1965. 22. Land and Water Conservation Fund Act of 1965. 23. Federal Water Project Recreation Act of 1965. 24. Concessions Policies Act of 1965 (in national parks, etc.) 25. National Wild and Scenic Rivers Act of 1968. 26. Estuarine Areas Act of 1968. 27. National Trails System Act of 1968. 28. Mining and Minerals Policy Act of 1970. 29. Clean Air Act of 1970, as amended, itf-. Resources Recovery Act of 1970. 31. Alaska Native Claims Settlement Act of 1971. 32. wild Horses and Burros Act of 1971. 33. Coastal Zone Management Act of 1972, as amended 34. Federal Water Pollution Control Act Amendments of 1972. 35. Marine Mammals Protection Act of 1972. tfft-. Endangered Species Act of 1973. 37. Trans Alaska Pipeline Authorization Act of 1973. 38. Flood Disaster Protection Act of 1972 39. Federal Energy Administration Act of 1974. 4&. Forest and Rangeland Renewable Resources Planning Act of 1974). 41. Fish and Wildlife Coordination Act of 1974. 42. Housing and Community Development Act of 1974. 43. Hoise Control Act of 1974. 44. Outer Continental Shelf Lands Act of 1975. 45. Federal Land Policy and Management Act (BLM Organic Act —1976), 46". National Forest Management Act of 1976. 47 Historic Preservation Acts. 48 Federal-Aid Highway Act, as amended. 49. Airport and Airway Development Act, as amended. 50. Federal Surplus Lands for Parks and Recreation Act.

444 PETROLEUM EXTRACTION INDUSTRY AND ENVIRONMENTAL CONTROLS INTERFACE

OVERVIEW

Virtually all environmental statutes apply to the Petroleum Extraction Industry. What is worse, the Environmental Protection Agency takes advantage of the industry, because no single association represents the Petroleum Extraction Industry. Accordingly, there is need for environmental attorneys to understand the application of the statutes and implementing regulations to the Petroleum Extraction Industry so adequate counsel can be given.

STATUTES

The following Federal statutes impact the Exploration and Production segment of the petroleum industry:

1. Clean Air Act - 42 USC Section 7401 et seq

2. Clean Water Act - 33 USC Section 1251/et seq.

3. Oil Pollution Act of 1990 - 46 USC Section 1007 et seq.

4. Safe Drinking Water Act - 42 USC Section 300f et seq.

5. Federal Insecticide, Fungicide and Rodenticide Act - 77 USC Section 136 et seq.

6. Toxic Substances Control Act 7 USC Section 136 et seq.

7. Resource Conservation and Recovery Act - 42 USC Section 6901 et seq.

8. Comprehensive Environmental Response, Compensation and Recovery Act - 42 USC Section 9601 et seq.

9. Superfund Amendments and Reauthorization Act - 42 USC Section 11002 et seq.

A portion of these statutes and implementing regulations will be discussed by other speakers. Unfortunately, not all of the issues can be covered because of the limited timed available. Additionally, state regulations have built upon the Federal regulations, typically increasing the severity of the controls.

1-24 PETROLEUM EXTRACTION INDUSTRY OPERATIONS

The industry is divided into 5 primary operations:

1. Exploration - looking for likely areas of oil or gas containing reservoirs

2. Drilling - the act of penetrating the earth to a depth where the oil or gas is expected or known to exist.

3. Producing - the process of bringing the oil or gas from the reservoir to the sales point.

4. Gas and/or sulfur plant operation - the physical separation of gas liquids [butane, propane] from natural gas.

5. Abandonment of facilities or operation - removal of facility when no long economically viable.

Exploration

Exploring for oil and gas reserves typically requires field geology and seismic work. Field geology is considered benign since it is facilitated by a lone field geologist typically on foot. However, if the geologist must enter Federal lands, permits are required from Mineral Management Service or Forest Service operation can require cutting of roads.

Seismic operation requires mobile equipment, either thumper or shot hole drilling operations. The Clean Air Act provisions apply to some trucks. The Clean Water Act regulations control the discharge of drilling fluids into Waters of the U.S. Further, some states require prescribed plugging and abandonment of the shot-hole.

Beyond these controls, little or no environmental statutes or implementing regulations apply to exploration activities.

Drilling Operations

Drilling includes the excavating of a drilled hole to a given depth. This requires use of large diesel engine driven equipment. The engines are controlled under the Clean Air Act since they emit criteria pollutants. However, onshore drilling operations are exempted from Clean Air Act permitting requirements because the drilling activity is a temporary activity. Offshore

1-25 drilling activities are permitted only in the Gulf of Mexico and are subject to the onshore state criteria pollutant limitations for any operation within 25 miles of shore.

Drilling is subject to all of the provisions of the Clean Water Act. In the states of Louisiana, New Mexico, Oklahoma and Texas, this means zero discharge to Waters of the U,.S. No other industry operates under such severe limitations.

The Clean Water Act not only limits or prohibits discharges under the National Discharge Elimination System [NPDES] permit, but requires storm water permits and Spill Prevention Control and Countermeasure [SPCC] [plans.

Further, offshore drilling operations are subject to the Response Plan provisions of the Oil Pollution Act of 1990 if 250 bbls of oil are transferred over water. The Oil Pollution Act applies to onshore drilling if fuel storage exceeds an unspecified quantity and no secondary containment is provided. Starch muds require biocides controlled by the Federal Insecticide, Fungicide and Rodenticide.

Additionally, the Toxic Substances Control Act Registry provisions apply as well as the Superfund Amendments and Reauthorization Act hazardous chemical notification and inventorying provisions. Also, the Suspect Hazard Reporting System {TSCA 8(e)] applies. [Refer to Producing Operations for more detail regarding these provisions.]

Drilling fluids are exempted under 42 USC 6921 (b)(2) from being classed as hazardous wastes. However, diesel fuel, drilling clay, barite, and caustic materials are subject to notification and inventorying provisions of the Superfund Amendments and Reauthorization Act.

Spent mud and cuttings are not subject to the Underground Injection provisions of the Safe Drinking Water Act if they are injected into the annulus between casings.

Producing Operations

Producing operations can be subject to all of the environmental statutes and implementing regulations.

1.26 Clean Air Act fCAAl

Compressor and water flood pump engines if grouped so as to constitute 250 tons of a criteria pollutant can be subject to the Prevention of Significant Deterioration and/or Non-attainment Construction permit requirements. Further, the Clean Air Act

Amendment;1! of 1990 subject facilities emitting 100 tons per year of a criteria pollutant or 10 tons p&r year of a Hazardous Air Pollutant [HAP] to operating permit requirements.

Non-attainment areas are divided into classes of non-compliance with the National Ambient Air Quality Standards ranging from marginal to severe. Each class requires increasing more severe controls and lower threshold values triggering controls.

Clean Water Act fCWAT

The Clean Water Act imposes controls or prohibitions on the discharge of contaminated liquids into Waters of the U.S. Currently, stripper wells can and do discharge produced water to Waters of the U.S. These controls are imposed in the form of National Discharge elimination System [NPDES] permits

Contaminated storm water leaving a facility via a conveyance and entering Waters of the U.S. require a Storm Water Permit. Exploration and Production facilities are exempt unless the facility experienced such a discharge within the last 3 years.

Any oil storage facility capable of containing 660 gallons in one tank or 1320 gallons in multiple tanks and reasonably expected to enter Waters of the U.S. if spilled must prepare and implement a Spill Prevention, Control and Countermeasure [SPCC] plan.

Oil Pollution Act of 1990 rOPA-901

The Oil Pollution Act of 1990 [OPA-90] is an extension of the Clean Water Act. OPA-90 requires onshore and offshore producing operations prepare Response Plans. We understand Coast Guard has set the threshold planning quantity for over water transfers of oil at 250 bbls. It is rumored, EPA has set the threshold at 1000 bbls. Mineral Management Service may propose a different threshold quantity.

1- 11 Additionally, OPA sets limits on oil spill clean-up financial liabilities. Offshore liability is $75 million plus clean-up costs. Onshore liability is $350 million. Finally, OPA-90 requirements imposes $150 million financial responsibility on offshore operators. No financial responsibility is imposed on onshore facilities.

Safe Drinking Water Act TSDWA1

The Safe Drinking Water Act controls:

1. Drinking water quality 2. Underground injection wells

Drinking Water Quality

Drinking water wells at field locations are subject to the sampling and analytical requirements of the Act. Not many operators own drinking water wells. Those who do post signs "non-potable water" and provide bottled water for consumption. Analysis of water samples include coliform, heavy metals, organics, pesticides and herbicides.

Underground Injection Control

The largest number of injection wells belong to the Petroleum Extraction industry. These wells [called Class II wells] are used for:

1. disposal of produced water 2. water flood injection 3. gas repressuring 4. polymer floods 5. insitu combustion [fire, floods] 6. steam injection

Implementing regulations mandate completion [construction] details, injection pressure and rate monitoring, well integrity monitoring and well permitting.

Federal Insecticide. Fungicide and Rodenticide Act FFIFRA1

FIFRA controls biocides and herbicides used for bacterial growth in tanks and wells. Also, FIFRA governs disposal of FIFRA controlled containers. 1-28 Toxic Substances Control Act fTSCAT

TSCA is responsible for elimination of polychlorinated biphenyls [PCB] used as a fire retardant in oil field electrical transformers and capacitors. TSCA also, prohibits use of any chemical not included in the TSCA Registry, i.e., treating chemicals. Further, TSCA requires implementation of a Suspect Hazard Reporting System use by employees to report hazards caused by manufacturing or processing operation, i.e., producing and treating crude oil.

Finally, TSCA mandates disposal controls for asbestos used in insulation of heaters.

Resource Conservation and Recovery Act fRCRAI

RCRA identifies and controls solid waste, i.e., solids, liquids and containerized gasses. Three types of solid waste are identified:

1. hazardous waste 2. non-hazardous waste 3. exempted waste

Almost no hazardous waste is generated in Exploration and Production facilities. Exceptions include, lead acid batteries, waste mercury and unused treating chemicals.

Non-hazardous waste includes paper, rags, boards, cans and sacks. Typically, drums are returned to the supplier when empty If the drums are not returnable, the lids are removed and the open cylinders crushed. Drums are considered empty if they contain less than 1 inch of material.

Most oil and gas ield wastes are exempted from being classed as hazardous. These include:

1. mud and cuttings 2. produced water 3. associated wastes

Water base muds are truly non-hazardous. Oil base muds can be combustible and are returned to the supplier for credit. Produced water is injected, discharged into tidaily affected waters, or discharge west of the 98th meridian for beneficial use [livestock and wild animal watering]. Associated waste means waste coming out of a well or flowline. 1- 29 The primary problem of waste in Exploration and Production is the disposal of non-hazardous waste into hazardous waste sites which become bankrupt. This triggers provisions of the Comprehensive Environmental Response, Compensation and Liability Act [CERCLA].

Comprehensive Environmental Response. Compensation and Liability Act TCERCLA1

CERCLA impacts producing operations in two ways:

1. Disposing of non-hazardous waste in a hazardous waste site which subsequently becomes bankrupt, i.e., Superfund Site

2. Hazardous Substance Releases

Superfund Sites

Past practices within the Petroleum Extraction Industry dictated calling a waste transporter [vacuum truck], loading the transporter and telling him to dispose of the waste. Time and time again this practice resulted in non-hazardous waste [drilling fluids, produced water or bilge water] deposited into hazardous waste sites. Increasingly stringent RCRA controls on hazardous waste sites or, in many cases, the passage of time resulted in legal hazardous waste sites being abandoned with or without adequate closure. These orphaned sites must be closed in accordance with existing regulations. Closure funds come from generators of the waste disposed in the site or from a federally mandated fund, called the Superfund.

Typical E&P operators become Possible Responsible Parties [PRP] because of non-hazardous or exempted waste [produced water, bilge water, drilling fluids] disposed into waste sites which were or have become orphaned hazardous waste sites.

Superfund financial responsibility also results from the "eminent and substantial threat" provision of CERCLA. Typically, the threat is imposed by the waste leachate entering ground water. Currently, four non-hazardous Superfund Sites exists; 3 in Louisiana and 1 in New Mexico. These sites store RCRA exempt wastes. Nevertheless, the generators are classed as PRP's and required to fund the closure.

1-30 Hazardous Substances

A hazardous substance is defined by 40 CFR Part 302. Each hazardous substance has an associated Reportable Quantity [RQJ at or above which EPA requires the operator report a release [into air, water or onto soil] to the National Response Center [Coast Guard].

Reportable Quantities range from 1 to 5000 pounds for hazardous substance, Attachment 1, found in E&P operations.

Superfund Amendments and Reauthorization Act TSARA1

SARA Title III is known alternately as Emergency Planning and pommunitv Rioht-to-Know. However, the regulated community refers to this Title as SARA Title III.

SARA Title III impacts the Petroleum Extraction Industry under the following Sections:

1. Section 302 - Extremely Hazardous Substances Notification

2. Section 303- Facility Emergency Response Coordinator

3. Section 304 - Extremely Hazardous Substance and/or Hazardous Substance Release at or above the RQ

4. Section 311 - Hazardous Chemical Notification

5. Section 312 - Hazardous Chemical Annual Inventory

6. Section 327 - Transportation Exemption

Extremely Hazardous Substances Notification

Section 302 requires each operator storing at or above the Threshold Planning Quantity [TPQ] of an Extremely Hazardous substance, [Attachment 1] notify the State Emergency Response Commission [SERC] of that presence. Sulfuric acid, chlorine, sulfur dioxide and acrolin are Extremely Hazardous Substances seen in the field, Attachment 1. With the exception of sulfuric acid [used for pH control in cooling towers] most Extremely Hazardous Substances have bee eliminated.

1- 31

' IT Facility Emergency Response Coordinator

Section 303 requires each operator subject to Section 302 notification appoint a facility coordinator responsible for reporting releases and for assisting the Local Emergency Response Committee [LEPC] develop Emergency Response Plan and Evacuation Plans.

Release Reporting

Section 3CK requires each operator subject to Section 302 report releases a Extremely Hazardous Substances and/or Hazardous Substances at or above the RQ, Attachment 1, which leave the facility boundaries.

Hazardous Chemical Notification

Section 311 requires each operator storing 10,000 pounds or more of a hazardous chemical [crude oil, sand, cement] at a single facility at any one time notify the SERC, LEPC and the Local Fire Department(s) serving the facility of that presence.

Hazardous Chemical Annual Inventory

Section 312 requires each operator subject to Section 311 prepare by 1 March of each year an inventory [Tier I or Tier II] of all hazardous chemicals present at the facility at or above 10,000 pounds during the previous calendar year. The inventory is sent to the same agencies as Section 311 notifications.

Transportation Exemption

SARA Title III applies to presence of all Extremely hazardous Substances at or above the TPQ; hazardous substances released at or above the RQ leaving the facility boundary; hazardous chemicals present at a facility at or above 10.000 pounds. What happens if a truck laden with one of these substances or chemicals enters a facility planning to offload a portion of the chemical?

Congress provided a transportation exemption in the form of Section 327 which exempts an operator from including chemicals present at the facility undar active shipping papers.

1-32

453 Gas and Sulfur Plant Operations

Gas and sulfur plant operations are subject to the same controls imposed upon producing operations. Additionally, the Clean Air Act imposes controls of fugitive emissions from valve stems, flanges, pump seals, compressor seals and reiief valves.

Also, the Clean Air act regulations specify the sulfur recovery efficiency from sour [hydrogen sulfide containing] gas when the gas is processed.

Abandonment Operations

Abandonment of E&P facilities can occur throughout the life of the field. However, most occur at the end of the economic life of the field.

At the completion of drilling, the reserve pit (mud pit] is closed permanently. No federal regulations control these closures. Typically, State rules control pit closures. Currency, Louisiana and Oklahoma are the only states imposing Limiting Constituent Criteria on heavy metals, chlorides, and Total Petroleum Hydrocarbons [TPH].

Producing and injection wells can be plugged and abandoned prior to field abandonment. States control producing well plugging and abandonment requirements. States and/or Federal rules control injection well plugging and abandonment procedures.

E&P facility abandonment are controlled by lease agreements. However, we see expanded use of the "imminent and substantial threat" provisions when leased lands are returned to the lessor.

1-33 I

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Charges

^ tn c o %wmm o NARUC/DOE CONFERENCE • April 27,1993

Larry Hall, President and COO K N Energy, Inc.

Outline of Remarks Accompanying Slide Presentation

0 Critical time for natural gas industry

0 Nation has opportunty and can benefit from significant domestic energy resources and environmentally clean fuel

0 Challenge of industry, marketplace and government to work together:

—new environment of deregulation at wellhead/ restructure services under Order 636

0 Address two areas relating to upstream issues in this new environment - from an integrated company's perspective

—gathering and processing after Order 636 --supply

0 Gathering and Processing Issue

—three elements in gathering sector of pre-636:

1) regulated gathering/pipelines-FERC 2) state regulated and unregulated gathering and processing - producer owned 3) GPM-new kids on block - unregulated 0 Post-636 • regulated unbundled/unregulated - FERC string

--level playing field with other unregulated responsive and decisive:

—well connects —expansions-risk —market based rates —market driven incentives

—adequate legal remedies:

—monopoly systems/discrimination -not a void for states to fill

0 Supply

—sufficient resource base to take us far into the next millenium

—short term deliverability issue

—strategic alliances:

— states --LDCs —pipelines —marketing companies --producers

Objective is reliable supply

0 First-drilling Activity -level of successful drilling activity and gas demand are two major factors that determine adequacy of natural gas productive capacity

-demand is up 19.8 TCF; over 20 TCF - 1993

-rig count and number of wells at historic lows --represents number of rigs actively drilling that have as their target natural gas discoveries/onshore and offshore-United States

0 Second productive capacity of dry gas barely exceeds output for 1993:

-two largest gas producing areas, Gulf Coast and Texas, not expected to meet historical market share - off shore 23% - 14 Bcf/D

—most of productive capacity comes from new well completions - wells less than three years contributed over 40% of December capacity - 1982-84; down to 33% 1992

—take 20,000 successful completions in next two years to keep necessary deliverability

0 Storage

—key 52 Bcf/D storage w/d capacity end of February 1993

-1.52 Tcf-17% decline over 1992; March 1.2 Tcf

-net injections needed to average 8.4 Bcf/d April-October to get to last year-low

-incremental demand of .75 Bcf/d to 1.3 Bcf/d

0 Price

—markets are telling us:

—gas prices higher in summer than winter

—gas prices higher next winter

—number of contracts on NYMEX running scared or real

0 Traditional Regulation Won't Work - Forging An Understanding for the Long Term Price and Service 0 Prices

—highest in decade

-what is market telling us:

--storage --decline in deliverability —636 uncertainty

0 States

-start asking questions - need to understand supply issue

—producers/marketers new role - communication -understand tools available - hedging; swaps; EFP; long- term contracts-fixed/indexed —focus on best purchasing practices, not least cost purchasing - least cost drives short term decisions - focuses on hindsight

—innovation - risk/reward - realistic objectives

One thing we have learned: cost based regulation does not incite cost minimization or innovative ways of doing business

Regulation is too often micro management where prospective strategies are laboriously scrutinized and past performance penalized

Traditional regulation will not work - forging an understanding for the long term price and service 0 Monitoring and Oversight to Prevent Abuses

0 It is Our Time

—our responsibility to make it work

—it is our country

—consistent/coherent vision - communicate o Order 636 Pipeline Restructuring PRE-RESTRUCTURING

,o°* f ' y Integrated Pipeline REGULATED ^

Independent Segments Order 636 Pipeline Restructuring RESTRUCTURED 404 U.S. Natural Gas Supply Versus Demand (Bcf/D)

Excess Deliverability

Dry Gas Output

1982 1983 1984 1965 1986 1987 1988 1989 1990 1991 1992 1993 Working Gas Injection Requirements (April-October Bcf/D) 9.10 9.60 8.40 7.80 6.70

1991 1992 1993 NYMEX Natural Gas Contracts Monthly Trading Volume (thousands of contracts) 250

200 - 1.94 Million Contracts Traded 150 During 1992

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0.00 i f-f-f •»• -I •• i--f""f-4~t---l M ^-f--!-f- OOOO Oi Q) &> & Gi 01 itit tS> K> O C* "New Horizons for Energy-Efficiency: Natural Gas Cooling"

Presented by

David R. Jones President and Chief Executive Officer Atlanta Gas Light Company

at the

DOE/NARUC Conference on Natural Gas Use New Orleans, Louisiana

April 28, 1993 Thank you.

I'm pleased to be able to talk with you today about natural gas cooling. Natural gas cooling is one of the most promising new markets for the natural gas industry; but, if you stop to think about it, natural gas cooling is not new.

We sold single step absorption cooling in the 60's & 70's with varying de- grees of success. As appliances became more efficient in the 1980s we needed new technology to be able to compete. Now new and improved technology such as absorption, engine driven and desiccant products will provide economical comfort and environmental benefits to users.

Today's natural gas cooling equipment is better and more efficient than the equipment sold 15 or 20 years ago. Sophisticated controls, added heat recovery, new construction materials and improved manufacturing quality control — all of those things have boosted the competitiveness of these products.

Just one example is the new direct-fired, double-effect absorption chiller that Trane, York and Snyder General are now selling. These chillers have co- efficients of performance more than double those of old single-effect units. In addition, today's equipment can provide both heating and cooling. As a result, gas cooling offers particularly good value in hospitals, hotels, restaurants and a variety of other commercial and industrial applications.

DUV There a number of new products on the horizon. For example, the triple effect absorption chiller developed by the Department of Energy that increases efficiencies by an additional 40 percent.

But why gas cooling? Why is it so important? To better explain the impor- tance of gas cooling, I need first to discuss the changes that are happening in the natural gas industry.

First, deregulation and Order 636 opened us up to a new world of increased competition within our industry as well as with others outside our industry.

Second, we are faced with declining annual use per customer for natural gas in residential and commercial markets. Use of natural gas is down in our core markets because of steadily improving efficiency in all end-uses, voluntary con- servation and — increasingly — integrated resource planning. The Georgia Pub- lic Service Commission is currently looking at my company's integrated resource plan — the first ever filed by a natural gas utility in the state. We expect a deci- sion from them on our proposals in June.

So our industry now finds itself in a situation where we must develop bold, new strategies to sell efficiency to our existing residential, commercial and in- dustrial customers. At the same time we must develop and market a number of new technologies that continue to improve the value of natural gas for consum- ers.

5..' Natural gas cooling fills the bill either way you look at it.

Gas cooling is perhaps the best demand side management option available for both electric and gas utilities from a technical standpoint.

For the natural gas industry this market fills the summer valley in gas load and helps spread the high transportation fixed cost that LDCs are being forced to assume through Order 636.

Electric utilities can avoid or postpone incurring the costs of building new generating capacity. The cost of new generating capacity needed to power elec- tric cooling is estimated anywhere from $250 per refrigerant ton to more than $2,000 per ton. That doesn't even include the cost of associated transmission and distribution upgrades.

The improved concept of total integrated resource planning can definitely help improve our nation's energy security — by making the best use of both gas and electric systems.

So you can see it becomes a win, win situation. Consumers' total energy costs are reduced. Even though gas cooling has higher first cost, lower operating cost results in modest payback on their equipment investment. Modern, efficient natural gas equipment also can reduce our dependence on imported energy supplies and improve our nation's energy security. Ninety-five percent of our gas supply comes from the lower 48 states. Our remaining require- ments are supplied by our neighbors to the north. Ample reserves of natural gas are available — more than 100 years of supply. All this helps U.S. energy secu- rity by reducing our dependence on foreign oil.

I'm pleased to report some significant progress in our efforts to market natural gas cooling.

In the commercial market we are having some success introducing gas cooling, especially with absorption coolers. Absorption's share of chiller market rose from 4 percent average in the 1980s to 8 percent in 1992, according to the Air Conditioning and Refrigeration Institute.

Our progress is still not nearly as impressive as in Japan, where absorption has 90 percent of the chiller market. Export market potential for gas cooling equipment is tremendous as other countries choose gas cooling over the expen- sive infrastructure needed to power electric cooling equipment. We must match and surpass Japan's challenge. For engine driven and desiccant gas cooling systems, we definitely need more marketing support. Desiccant systems have great potential where large amounts of cooling are needed and where the problem of mold and mildew caused by humidity is significant. A good example is the Swan Hotel at Walt Disney World in Orlando, Florida. Two months after they installed a desiccant system they reported significant reductions in the relative humidity, as well as improved comfort levels.

Mold and mildew cost the hotel industry around $70 million a year in dam- ages and lost revenue. Humidity control is also a major concern in supermarkets, hospitals, offices and other building-types where high humidity causes opera- tional and indoor air quality problems.

Desiccant systems also can eliminate capacity and efficiency reductions that accompany converting chillers from CFCs to alternate refrigerants. Another shot in the arm for this market is the development and introduction of desiccant- based total cooling systems.

There remains significant potential for gas cooling in the industrial markets but so far most of the activity has been in commercial and residential applica- tions. For the residential customers, gas cooling is a promising market in all the Southern states. But it hasn't always been that way. More than 30 years ago I started my career selling natural gas cooling, and back then it was a hard sell and it is still a hard sell. But today, with technological breakthroughs like the York Gas Heat Pump — a unit that both heats and cools — we have a strong story to tell.

The York Gas Heat Pump will give a giant boost to natural gas in the resi- dential and small commercial cooling market. This unit will be the most efficient heating and cooling unit on the market, and our challenge is to make customers aware of its many benefits.

The York Gas Heat Pump provides superior comfort in the winter by deliv- ering air at a warmer temperature than conventional electric heat pumps. This is possible by capturing the heat of the advanced natural gas engine. In the summer, the York unit will better handle humidity by utilizing a variable speed compres- sor and a variable speed evaporator fan.

In terms of efficiency, the York unit is the best. According to the U.S. Envi- ronmental Protection Agency's forthcoming report on residential space condition- ing, the York Gas Heat Pump exhibits higher efficiency for both the heating and cooling cycles than any other air source product on the market today. Emissions are a critical yardstick by which we must measure cooling tech- nologies today. The York Gas Heat Pump's high efficiency means far fewer emis- sions than other technologies across the board. It emits no SO2, and NOX emis- sions are at very low levels — well within air quality requirements. This product currently uses HCFC refrigerant and can easily be converted to other refriger- ants.

The York Gas Heat Pump can also outperform its electric counterparts in terms of reliability, lu advanced natural gas engine designed specifically for heat pump duty, coupled with a heavy-duty compressor, yields a 15-year life expecta- tion, with only annual maintenance required.

The American Gas Cooling Center, which shares its headquarters with the American Gas Association, directly supports technology transfer and commer- cialization of advanced gas cooling equipment. The Center's goal is to establish gas cooling as an attractive alternative to electric systems.

Right now, the Center, the American Gas Association, and the Gas Re- search Institute are jointly involved in a field demonstration of 50 York units. Once this demonstration is finished — around the end of this year — we'll begin marketing the York Gas Heat Pump. The goal is to sell 50,000 units in the next four years.

506 The York Gas Heat Pump manufacturer's group will invest $13.3 million for capital tooling, while the gas industry has earmarked $14.5 million to bring the product to market at the mature market price.

I might mention that we're working hard to involve the federal government in this effort. We would like the federal government to commit one half of the $14.5 million. The payback for the federal government will be both economic and environmental. More natural gas use is in the national interest — it keeps jobs and dollars at home. Keep in mind that there is a tremendous export poten- tial for this technology. Many governments, especially those of the Pacific rim, are actively supporting the use of gas heating and cooling to take advantage of their abundant supplies of natural gas. With the support of our government we can make a real impact on this emerging export market.

I think the York unit is the tip of the iceberg. Other absorption and adsorp- tion technologies will be developed to create alternatives and competition in this growing residential and small commercial market.

507 As with the introduction of any new product, we face major challenges, but I think they are challenges we can meet head on. We have to look at the high first-cost of the equipment and achieve a marketable price. We will have to build an infrastructure to address the currently limited sales and service capabilities of vendors. We must work closely to educate users and design engineers who have been so far uncomfortable with gas cooling. And perhaps our biggest challenge will be to work with the electric utilities, where gas cooling is considered a com- petitive threat.

Natural gas cooling can be an important tool for us as we move into the era of integrated resource planning programs. Gas cooling can help shave electric peak demand and help balance the gas industry's load factor year-round.

What's more, the timing is right. America's growing awareness of the need to clean up our environment, to increase our energy security, and to keep jobs and dollars right here at home, play right into our hand. Both in government and the private sector Americans understand that clean-burning natural gas is the fuel of choice.

-END-

508 GRI'S IMPACT ON COOLING MARKET NEW END-USE MARKETS

• Goal DOE/NARUC Conference - Develop and Deploy Gas Cooling Technologies That Offer the Consumer Environmen'jl and Economic New Orleans, LA Benefits and Can Contribute to oas Utility Load April 27, 1993 Leveling and Decreasing Peak Electric Demand.

• Market Impact - 800,000 Tons by 2000 Presented by. David O Webb Senior Vice President PoHcy and Regulatory Allans

I

MARKET DRIVERS FOR GAS TECHNOLOGY AND PRODUCT COOLING DEVELOPMENT Today: • Absorption CMNw/Heater • Gas Engine Heat Pump (York-Tram-Carrier) • Oesiccant Dehumidifiers • First Generation Technology • Engine ChNtora - Supermarkets • Engine Roof Top Units - Hotel/Motel • Development of Advanced Technology Tomorrow: • GAX Absorption • Adsorption and Chemisorption • Triple Effect Absorption • Deslccant Cooling Products • Market Penetration/Deployment Advanced Engine Chillers ,: t M, '. »!:,•) 1- . c: .it 1:. : • '• r.,< ., i c <| ::. ;!:u-. IWIUI t>

1 Mi Ai'T • :!• TECHNOLOGY AND PRODUCT DEVELOPMENT

•v*:i' 7'J1; of all •-K'« '• I'Olii'ij t.Ji>nm)(.' Today: ijtil ! in tin.- iii_-xt. :-'• ycvi.'.s V.JJ1 • AteorpNon ChNtor/H«at«f • Gas Engine Heal Pump • •i.i.taiii '.-KI 'ii-vi'li.j t-.i ti.v.'hiiolu'!y. (York - Tran* - Carrier) • Deslccant Dehumidifiers • Engirt* CMM*r« - Supermarkets • EnghM Roof Top Units - Hotel/Motel

; Tomorrow: • GAX Absorption • Adsorption and Chemisorption • Triple Effect Absorption • Deslccant Cooling Products Advanced Engine Chillers ADVANCED TECHNOLOGY MARKET PENETRATION

Needed: Greater Number of Units in the Market Needed: Increased Efficiency Propoaal: State Regulators: Acceptance of Life-Cycle Lower First Costs Costing, Fuel Switching, IRPs Proposal: 5 Year Joint Effort DOE/GRI/lndustry Industry: "Champions" to Sponsor Gas Cooling Programs DOE: $57 Million GRI/lndustry: $57 Million GRI/DOE: Improved Technology to Lower First Costs

VEHICLE MARKET PROGRAM DRIVERS FOR NGVs • Goal - Develop and Deploy Natural Gas Vehicles and Supporting Infrastructure Such That Gas Consumers Can benefit from the Economic, Environmental, and Energy • OEMs Security Value of Natural Gas and the Gas Industry Can Gain a Stable and Substantial New Year-Round Load. Technical Hurdles e Market Impact -1,000,000 NGV* on the Road by 2000 Refueling Infrastructure - 5,000 Fueling Stations by 2000 Creating Markets

11 OEMs

• GRI and Industry Have Committed $100 Million • Dedicated Vehicles Are Emerging

One til llw iiisermce transit busts puweied liy Hie luimji-gjs-tiieleil t'.ummms 110 c/njuw 13

NGV PROGRESS IN MEETING CARB EMISSION STANDARDS (3751-5750 LB. TW) Emltdon Laval (g/ml.>

NMHC (NMOG lor Standard) CO NO, hillMJt'/(/U>:» int'/iwj^j/tuned1! enth 01 *ttuiinnuw imvt <7IJS^ -.uUm/intluii't willr, CU LEV Standards •§ Typical Conversion, Dodge Ram Van • ULEV Standard* H Range ol Prototype OEM NGVs TECHNICAL HURDLES REFUELING INFRASTRUCTURE

Needed: Next Generation Storage Needed: Cost Improvements in Refueling System Cylinders (Components, Meters, Dispensers, System Integrations)

Proposed: 5 Year Joint Effort DOE/GRI/ Proposal: 5 Year Joint Effort industry $5 Million Each DOE: $40 Million GRI/lndustry: $20 Million

17

CREATING MARKETS NEXT STEPS

Needed: Fleet Programs • Meaningful Partnership Between GRI/DOE/lndustry Federal/State Initiatives • Annual Cofunding (50/50) Legislative and Regulatory Incentives $50 Million Each in NGVs, Cooling, Industrial Processes, Regulatory Rate Flexibility Fuel Cells, Power Generating, Storage COFUNDING BENEFITS

• Results in a Shorter Timetable for Technology Development • Eliminates Duplication of R&D • Encourages Efficient Utilization of Natural Gas • Maximizes the Environmental Benefits • Increased Gas R&D is Consistent with Clinton Administration Energy Policy

21 DOE/NARUC NATIONAL CONFERENCE ON NATURAL GAS USE STATE REGULATION AND MARKET DYNAMICS IN THE POST 636/ENERGY POLICY ACT ERA

NEW ORLEANS APRIL 26-28,1993

"NEW END USE MARKETS"

JAMES V. MAHONEY VICE PRESIDENT NEW ENGLAND POWER SERVICE COMPANY MARKETING GAS TO ELECTRIC GENERATION

GREAT GROWTH OPPORTUNITY

CUSTOMER EXPECTATIONS ARE CHANGING

"COMPETITORS" UNLIKELY TO ROLLOVER

UTILITIES WILL DEVELOP NEW OPTIONS NEPOOL ENERGY MIX FORECAST

160

140 - PURCHASES 120 - OIL •B 100 g NATURAL GAS 80 ALTERNATES I 60 COAL

40 NUCLEAR 33% 37% 3396 20

0 7% 7% 5% HYDRO 1990 1995 2000 YEARS ELECTRICITY MARKET - TODAY|

SHORT TERM r PURCHASES

FRIENDLY FRIENDLY UTILITY UTILITY MERCHANT TRANSMISSION UTILITY SELF GEN. GEN. A/W CUSTOMER

IMPORTS i DSM J IRP fttiffi PROCESS ELECTRICITY MARKET - THE FUTURE|

OTHER UTEL. GEN. DSM VENDORS

en

FRIENDLY TRANSMISSION SELF SERVICE GEN.

BROKERS/ CUSTOMIZED UTILITY AGGREGATORS [EZfM: r mmmr SERVICE NEW RULES OF THE GAME |

ELECTRICS ran^w^-j|OSTd36_.

SHORT TERM COMITMENTS/SHORT "7(c)" SERVICE/LENGTHY LEAD TIME CERTIFICATE PROCESS MARKET BASED SERVICES INCREMENTAL RATES

LOAD FOLLOWING FLEXIBILITY TIGHTER OPERATONAL TOLERANCES

' MARKET INTEGRATION 1 SEPARATISM AND PENALTIES

» TOOLS TO MANAGE COMMITMENTS • UNCERTAINTY - "RE"-NOMINATIONS - IMBALANCE NETTING/TRADING - RECEIPT/DELIVERY POINT FLEXIBILITY ~ RELEASE RIGHTS - 7 - STORAGE - 9 TRADITIONAL METHODS WILL NO LONGER WORK

A FIRM LONG TERM ^TRANSPORTATION; \ UPPLY CONTRACT ELECTIUC GENERATION I HOW WILL ELECTRICS BEHAVE ? GAS POOLS! |

200 MW COMBINED-CYCLE UNIT DUAL FUEL PLANT

FIRM TRANSPORTATION

fNTERRUPTIBLE MO Ml Ut Tdt M lOtW 7iOO «dO MO HlM TRANSPORTATION 400 MW STEAM GENERATOR

SEASONAL/ RECALL RIGHTS

SHORT TERM FIRM —

L*• iM 7sM *M HcM *4t 2m M M* ll*»l AM IDf STORAGE 100 MW COMBUSTION TURBINES

tm • I MM PIPELINE/THIRD PARTY SERVICES MM - - BALANCING - SUPPLY MM ' - RELEASE fct* TtM fcM 2.-M 3J* 54* AM 111 NATURAL GAS HAS COMPETITORS PHYSICAL FUEL PURCHASES

S09 COMPLIANCE EXAMPLE

BUBBLE WITH OTHER PLANTS - OPTIMIZE SPREADS

PLAY SEASONAL SWINGS

COMPLIANCE DECISIONS

FUEL & ALLOWANCE FUTURES

TRADING Fuel Switching: SO2 Removal Costs

Versus 2;2% Sulphur Residual Fuel Oil $/ton of S02 Removed 1,400 0.3%

. . .. -„. .- _ _ . ... 1,200 -- " -" - 1.0% 1,000 NatGas 800

600

400 - 7—-—^-••vsr a A 200 - \-—y — - * •

0 (200) i , , t . i . . Jan'9i 1 .Apr "91, Jul'91- Oct'91» Jan'92, Apr'92 Jul'92 Oct'92 fJan'93 Apr'93 .' • : . ~ Month , ''. Natural Gas and 2.2% Sulphur Rule

versus 1.0% at both plants $/mmbtu 0

(too; (1.20; d 4(4 Apr'91- «Jur9i» OcC'91 Month

^ Daily Fuel Flexibility - Simplified

$/mmbtu 2.60 BP on 1.0% SH on',1.0%^ BPonO,7% SHon1,5% BP on NG SH on 2.2% APR 01 '93 33:21PM p.2

RESIDENTTAi, by Rod Lemon, Fh.D. Natural Gas Industry Specialist Monmouth College (IL)

The major issues regarding residential natural gas service it die itate level include the extent by which LDC services should be unbundled, rate design / cost allocation among customer classes and die terms of service, and the proper incentives for the regulated utility in an environment where there exists considerably more choices. These three issues axe interrelated. Given that my time is short, raypresentatio n win largely focus on die issue of whether unbundling should start at the residential cuitomers' burner-tip. first, unbundling **H\ take place at ttie reddenrial burner-tip. My presentation will present finding! of tho Toronto, Canada program wherein around 40% of all residential customers have elected to purchase gas from tintd-party suppliers. Who are these alternative merchants? Which type of residential customer chooses which merchant? What differences exist in die type of gas supply services provided by the alternate merchants? What gains exist or are perceived toexis t that drive tMi alternative contracting?

Second, cettaia myths surround the discussion of tmbnndlhig LDC services aD the way to the residential customer's burner-tip. Myth #1: Residential customer is not knowledgeable enough to make rational choice and is too small to carry this out efficiently. Reality: Residential customers are going to use agents. These agents can be bended. Residential customers make diis type of choice for other products. Mvth #2: Very high administrative costs will be incurred by die gas distributor if unbundling to die residential burner-tip was pf"""^, Rffftlity A computer can easily handle die hilling. The residential customer will not develop a new peak load pattern once this residential customer uses a durd-party merchant. fty- If die customer wants to switch merchants, there will bu stranded costs. Reality: Transactions wiH be governed by contracts. Firms will be at risk; dieir stranded costs are

1 Overview of presentation fordeliver y at the DOB/NARTJC Conference on Natural Gas Use, New Orleans, March 27, 1993.

0«-0l-93 04:23PM POO2 842 APR 01 '93 03:22PM P-3

their business. Myth #4. The third-party merchant may go belly-up, and the LDC must then provide back- up service and traditional customers will be cxoM-fubsidizing those that had shifted and now come back to the LDC. KcaUiy.: The Commission need not requite die LDC to provide back-up without adequate compensation. Reasons exist why other third-party merchants will seek these customers at a competitive price; further, mese customers may not seek the LDC as its new supplier. The service obligation of the LDC is to maintain, expand, and insure the operation integrity of its distribution system. Other obligations can be earned out by any number of firms.

Third, related issues may be the key to positions held on unbundling. There are two dimensions. State commissions must have a policy with regards to storage and local supplemental gas peaking facilities (propane, LNG, SNG) owned by the distributor. These could become separate companies. Various proposals exist on the manner by which these facilities could be either divested from or made affiliated entities of the gas distributor. Once separated, these services may be rip for deregulation. The third-party merchants will not only contract for gas Ripply; these third-party merchants will also contract for transmission capacity, storage, etc. They will buy and sell in the secondary market for pipeline and storage opacity. The LDC may find itself with contracts for capacity that are no longer necessary and whose price in the capacity release market may exceed or come short of the stated tariff price.

Fourth, freedom for die distributor to offer different services to different customers. Great freedom should be permitted to offer different services with legitimate qualifications, but customers or their agents should also have parallel freedom to purchase different services with legitimate qualification*.

Fif ih, state regulation becomes far more narrowly defined. The price of gas supply can be regulated by competition among alternative merchants. That is, deregulation is feasible. The PUC need not determine whether the spot market price in Texas or in Colorado is the best indicator of the competitive price of natural gas, need not determine whether gas supply requirements two months from now should be hedged, need not determine what portion of the gas supply contracts should be spot or long-term? Customers choice of alternative merchants will make these type of decisions.

5'J8 R-98% 04-01-93 04:23PM P003 842 APR 01 '93 03:22PM p

What happens to die state conutdssiod oversight of die gu distributor's contracting for pipeline capacity storage, Again, competition will regulate. Whedter (he capacity should be under three-year or twenty-year contracts, whether die capacity should be purchased on die capacity release maziest, etc will be dfttgrmtn^ by customers choice of alternative merchants. Prudence inquiries and state regulation BOW becomes focused only upon die gus distribution system.

Thus, net benefits of unbundllag to the bumertip are: • More accurate prices, • Better principal-agent dealings, • New dynamics at FERC, • Services matched better to the preferences, • Residential consumer! gain tfaebeneiflti of a more competitive natural gu industry, • Utilization of natural gas increases, and • Wasteful investments decrease.

04-01-93 04:23PM P004 #42 WHAT IS THE REAL FEDERAL POUCYFOR RESIDENTIAL NATURAL GAS USE

Presented by: Margaret Ann Samuels Federal Counsel Office of the Consumers' Counsel State of Ohio 77 South High Street/15th Floor Columbus, OH 43266-0550 (614) 466-8574

Presented at: DOE/NARUC Conference on Natural Gas Use New Orleans, LA

April 27, 1993

5.30 The theme of this panel is residential gas markets and their potential in the new competitive world of natural gas. LDCs continually reassure us that residential consumers are an important market. Certainly LDCs are devoting a major share of their resources to serving residentials. In part this is involuntary; as more and more larger gas users switch to' transportation of gas, residential users constitute an ever greater portion of the LDCs's sales. LDCs are about the only ones supporting residential concerns, however. Commissioner Heintz of Maryland pretty much laid out the gas industry position at lunch yesterday, sounding the theme that residential customers should pay for everything and stop whining. It's good to*- us.

I would like to postulate that the residential market is multifaceted just like other markets. A variety of responses to its needs is appropriate. Some residential consumers will want choices; some will not. Some will buy gas air conditioners — some may even buy NGVs. There is need for greater demand side management and conservation to reduce peak use. There is also potential for expanded gas use, particularly in natural gas air conditioning. However, I submit that the current regulatory efforts to shift costs of every description to captive firm customers is not the best way to promote natural gas use by residential consumers.

531 Yet at every turn the regulatory solution being proposed in response to competitive forces in the natural gas market is: Customers with competitive options don't want to pay whatever cost is at issue; let's put it in the demand charge and let the residential consumers pay it. Thus residentials are not seeing the benefits of increased competition but are paying for them for others. I will come back to this theme. First, I want to point out the kinds of factors that do influence consumers in their energy choices. To begin with, I think that gas is a wonderful energy source. Several NASUCA members took part in a focus group for the National Petroleum Council study last year. Afterwards we heard that the observers were amazed that we were really reasonable people. We really are. And residential consumers make rational choices. Three factors influence energy choices — and probably most other choices — for consumers. I have called these the economic, aesthetic and moral factors. The economic factor is primary for most of us, and most of these comments reflect that fact. But certainly aesthetic factors are also important, aesthetic elements that affect our energy choices include such desirable qualities as quiet operation, and absence of bad smells. The third factor influences us in ways that may be externally imposed. ) Moral factor is name I give to

-2- influences such as environmental issues, excessive depletion of natural resources, or income inequities. Of course if one has enough income, the economic factor can become secondary to aesthetic and moral influences. There is currently an automobile commercial proclaiming that we all have mind, heart and conscience, and we should want our cars' to have the same. I guess we consumers want our utilities and regulators to have mind, heart and conscience as well. Consumers follow heart and conscience when they can, but the mind usually zeroes in on the economic consequences. An example from close to home comes to mind. One of my sons wants me to buy Ben and Jerry's ice cream because of their social policies. I'm sure he's right — but it's a difficult choice when another brand is on sale at half the cost. The economic factor, as it so often does, weighs powerfully aqainst the moral factor.

For utilities or producers or manufacturers wanting to influence consumers to greater usage of natural gas, I suggest all three factors must be considered. Regulators may be motivated for societal and political reasons to encourage either greater or lesser consumption. Regulators exercise their influence at the moral and economic levels especially.

Let me tell you how I heat my home. My central heating is economical, moral and aesthetic. I have a gravity natural gas furnace that heats the house with no fan — thus no electricity

-3- consumption and no noise. The house has good insulation, and is comfortable with low energy use. Not totally moral/ however — I do have a fireplace — but it gives me immense aesthetic rewards, and I put the ashes on my garden. Next time I choose a heating system or systems, my choices will be influenced by all three factors. Proponents of the moral forces, such as environmental advocates, don't have a lot of money to influence choices. There's not a lot of money in conservation — at least, not yet. Thus, legislators and regulators are most often the forces to enable results in the moral category such as the Clean Air Act and investment in conservation. Sometimes legislators force the goals on the regulators by a failure to deal with what are really socia] problems. I am thinking of programs to solve low income energy bills by putting costs on utility users instead of on taxpayers.

Economic forces are the ones that consumer advocates constantly face. We are now facing the economic consequences of the so-called competitive market that is the current federal energy policy, and which states regulators must also deal with. I must note that federal policy with respect to gas use is not crystal clear. We have the Energy Policy Act, supposed to encourage increased natural gas use, to reconcile with the proposed Btu tax, supposed to encourage conservation, and Senator Johnston's mention of another policy, that the market does a better job of allocating natural resources. But I question whether energy policy as promulgated by the FERC is to increase or even encourage gas use by residential consumers. The policies discussed here primarily are those which affect base rates of pipelines and LDCs. They involve rate design issues and surcharges directed specifically at consumers without competition alternatives. The FERC policy of shifting pipeline costs to the demand charge, culminating in Order No. 636's mandate of the straight fixed variable rate design, is resulting in increasing rates to the residential heating customer. That trend is accelerating at an alarming pace. Other Order 636-induced costs under the umbrella of transition coats are in the billions. In the response of FERC Chair Betsy Moler to Congressman John Dingell, FERC's chart of transition costs did not even reflect available data as of the date it was prepared. Our office assembled transition cost estimates from ten pipelines affecting Ohio. As of April 23 the total for those ten pipelines w?s $2,518.3 to $2612.6 billion for gas supply realignment. That total does not include any estimate of the claims that Columbia Gas Transmission may submit. A large segment of these so-called transition costs will be billed to residential consumer class. FERC did not consider the cost of pipeline expansion in its estimates. The cost of new facilities is one that must also be a concern to residentials as firms seek rolled in pricing for new projects to serve expanding markets.

-5- Another cost recently added to pipeline demand billing is a demand surcharge for the Gas Research Institute. Up until the beginning of 1993 GRI was funded by a volumetric surcharge on all pipeline throughput. But pipeline claims that competitive forces were causing them to fund GRI with shareholder dollars persuaded FERC to shift $43 million, or 25% of GRI costs, to firm customers as a demand surcharge on top of the* volumetric charge. In 1994 the shift will be even greater. But we are told, residential consumers should pay gladly. It's good for us .

As a result of the changed billing mechanism for GRI, resident and commercial customers will pay 86% of GRI costs. LDCs will want to pass through those billings in their purchased gas adjustment rates. Yet GRI research costs are not a cost of gas -- in fact, after the change in the billing mechanism they are no longer even connected to gas consumption. In Ohio we have argued that it should be a base rate component just like dues to any other organization so long as change remains. (Ohio Consumers' Counsel and the California FUC have also appealed the GRI demand charge billing to the D.C. Circuit.)

The next cost being added to gas bills will only hit customers of four pipelines but they cover most of the central and eastern portions of the U.S. FERC in recent orders on the ANR and Tennessee pipeline restructurings has extended transition cost treatment to above-market costs of synthetic gas from the Great Plains coal

-6- gasification plant. Even though FERC admits this action flies in the face of Order No. 636, this gas, which is both costly and unneeded, will be permitted to flow. The pipelines are required to purchase it, and FERC plans to permit them to assess the excess costs to all firm customers on their systems, for another fifteen years. The premises supporting the original approval of the Great Plains gas have disappeared. Most significantly, studies show that the plant can be put to other, more economic uses not requiring ratepayer subsidy. No jobs need be lost, and the distortion caused by sale of gas at twice recent market prices could end. The Office of Consumers' Counsel opposes continuing ratepayer subsidies which have cost an estimated $750 million in the last ten years and now are being spread to firm customers throughout a large part of the country. We p.re joining efforts by the Wisconsin Distributor Group to end the subsidy and require synthetic gas to compete in the market like every other gas supply. So are a number of other entities, all opposed to the uneconomic aspects of continuing to produce synthetic pipeline gas from this plant, especially when other alternatives are available for the plant.

Turning from FERC to the Departments of Energy and Treasury, the proposed Btu tax measures are accompanied with the administrative intent to ensure that end users pay the tax -- and to remove state regulatory discretion to deal with the

-7- taxes — even if existing rates are already overrecovering LDC returns. I can't improve on Peter Bradford's comments earlier in this conference. NASUCA has now adopted a resolution calling for state and local authority over ratemaking treatment of any federal taxes affecting utilities. Turning to the state level, we find that increased gas use again results in higher rates for consumers -- or at least that result is being sought. Natural Gas Vehicles are great for the environment — and the fuel is cheaper. Problems; like weight, incremental cost and refueling infrastructure are being addressed — but of course that costs money. Some is coming from GRI, some from manufacturers -- and now LDCs are applying for ratepayer funding of their own research and promotional programs for NGVs. Such ratemaking treatment would not be subject to competitive forces but would simply be underwritten by gas users — even though NGV promotion is unrelated to their gas service.

If NGVs are serving a social objective, ratepayer financing is not a proper way to fund their development. Don't put them in gas rates and expect consumers to buy more gas. Separate ratepayers from discretionary funding of services — as advocated by Mr. Zielinski of Rochester Telephone. Residential ratepayers are not an inelastic market. A lesson from 1980s — that is true.

-8- There are no franchise territories for gas in Ohio — although few places where dual service choice actually available. You can bet rates of large users on the fringes of a de facto service territory or near pipelines are not subsidizing any other customers. State Actions re Residential Usage:

* Commissioners working hard to Ceal with 636. * Ohio roundtable and subcommittees, to consider the effect of 636 on all segments of the gas industry in Ohio. * NJ bi-monthly conferences, to acquaint regulators and industry participants with the issues. * KY process, recently begun, has a similar purpose. * Pressures to "unbundle" at state level are now being brought to bear; intended to increase even more the cost burden on residentials. * 636 shift of purchasing to LDCs causes costs for supply-related Staff and electronics capabilities for the LDCs. May work out in long run but higher rates likely — one Ohio LDC adding 28 staff persons for gas acquisition. Yet for their primary supplier, pipeline rates went up not down. * GRI, local NGV promotion costs in rates pipeline and LDC expansion costs.

What to do? If you are going Lo play the card game, you've got to deal sometime. Regulation needs to recognize that where increased gas use has cost, that should not be dealt to existing firm gas use.

* Laws are enhancing increased gas use for electric generation, ngvs - why? * Load factors; storage can be an extremely useful means of decreasing cost - if SFV stays in effect. * IRP - education re DSM will be increasingly critical

-9- Obligation to serve disappears with transportation of gas. if a customer leaves purchase of system gas, no obligation to take it back on the part of the LDC; if supply or capacity not available, the customer must be aware it is at risk. if a customer leaves purchase, and pipeline capacity can be reduced, any expense of maintaining or regaining that capacity should not fall on us, the remaining ratepayers. Residential gas transport — can help with gas costs in some instances but base rates for delivery may even increase. All electric generation — is that the federal policy for the future? As more and more costs shift to those who use gas for heat, that is the question I leave with you.

-10- DESIGNING PURCHASED GAS ADJUSTMENT CLAUSES TO PROVIDE FOR INCENTIVE COMPATIBILITY IN A MORE COMPETITIVE ENVIRONMENT

Robert E. Burns & Mark Eifert1 Senior Research Specialist & Graduate Research Associate The National Regulatory Research Institute 1080 Carmack Road Columbus, Ohio (614) 292-9307

Traditionally, automatic adjustment clauses have been generally accepted as a part of a utilities' tariffs for three primary reasons.2 First, the items generally constitute a significant or large component of the utility's total operating cost. Second, their costs, whether it be gas, coal, labor cost, interest, or other costs, change in volatile and unpredictable ways. Third, the price of purchased items (commonly fuel or purchased power) was considered entirely outside of the utility's control. Recently, the issue has been raised as to whether these assumptions are still valid. Clearly, fuel and purchased gas costs, while generally down from previous peak levels, still constitute a significant portion of a utility's operating costs. However, an argument might be made as to whether fuel costs have remained volatile and unpredictable. Casual observation seems to suggest less price volatility than in years past. But, can we expect this relative calm of recent years to continue? The answer is probably not.

An increase in the volatility of gas and coal prices can be expected in large part because of the Clean Air Act Amendments of 1990. The United States Energy Information Administration predicts a heavy reliance on gas, nonutility generation (usually gas-fired), and low-sulfur coal for future generation. This increased reliance on gas should have a profound effect on purchased-gas adjustment clauses.

1 The views expressed in this paper are the authors' own and do not necessarily reflect thr -e of The National Regulatory Research Institute, The Ohio State University, the National Association of Regulatory Utility Commissioners, or any of the individual state public utility commissions.

2 Much of this paper is based on work performed by the authors in Robert E. Burns, Mark Eifert, and Peter A. Nagler, Current PGA and FAC Practices: Implications for Ratemaking in Competitive Markets (Columbus, Ohio: The National Regulatory Research Institute, 1991).

541 Unless a utility is vertically integrated and controls its own fuel supply sources, it is unlikely that the utility can exert much control over the cost of purchased gas. However, this does not mean it exerts no control whatsoever, or that it is excused from hard-nosed, tough bargaining. Indeed, at the margin, a prudent utility would incur costs to search for less expensive fuel supplies up to the expected benefits, that is, the probability of successfully finding a lower price times the price savings times the amount expected to be purchased.

For purchased-gas adjustment clauses, the three grounds for having an automatic adjustment clause still hold, except when a utility owns an affiliated fuel source. But, the current trend is toward more open markets as evidenced in the electric sector by the growth in bulk power purchases, including those from QFs and IPPs, and evidenced in the gas sector by more direct gas purchases and the greater demand for transportation service. These market patterns create a need to revisit automatic adjustment clauses; particularly, the incentives they create and their ratemaking implications are in a more competitive environment.

The three traditional justifications for use of automatic adjustment clauses, while still necessary, are unable to test their appropriateness in a more open market environment. An additional justification is needed for the continued use of purchased- gas adjustment clauses. The operation of any automatic adjustment clause should provide incentive compatibility in a more open market environment. Automatic adjustment clauses should be designed to encourage utilities to act in their own best interest, maximizing profits by minimizing co«ts. Clauses should promote efficient behavior on the part of the utilities while quickly and accurately passing through fuel price changes to customers so they can make rational choices about supply, consumption level, or purchase of substitute goods.

There is a need to redesign state PGAs to meet this final criterion. Based on an NRRI survey conducted in 1991, most state commissions have not altered their PGAs and FACs in any significant manner to accommodate today's more competitive environment. Most state commissions still resort to either ex-post prudence reviews or best-cost fuel procurement planning with subsequent reviews to determine whether the utility is pursuing an appropriate fuel and/or purchase power procurement strategy. However, both of these approaches are fundamentally flawed, because they are unlikely to encourage efficient behavior on the part of the utility.

An ex post prudence review, if properly conducted, has one principal advantage. When properly applied, it can result in an appropriate allocation of risks between stockholders and ratepayers. It can allocate systematic risk (that is, uncontrollable market risks) to the utility, and idiosyncratic (controllable utility-specific) risks on the ratepayers.3

3 See Robert E. Burns et al., The Prudent Investment Test in the 1980s (Columbus, Ohio: The National Regulatory Research Institute, 1985). This report also sets forth four standards that must be met for the proper application of the prudence test. But, an ex post prudence review has the disadvantage of not encouraging the utility with clear signals to minimize the utility's total fuel costs, including the transaction cost of searching for and acquiring the lowest cost reliable fuel. This follows because all cost savings from a more efficient fuel portfolio are passed through to ratepayers, if not immediately, then within a short period. Without some positive benefit, utilities will tend to be more passive and cautious in fuel procurement, emphasizing stable (read static) and reliable fuel sources ovar less costly alternatives, whose substantial price discount may more than offset anv disadvantage from lower reliability.

The use of "least-cost" or "best-cost" ex ante fuel procurement reviews, on the other hand, are actually forms of preapproval meant to shift risks away from the utilities and toward ratepayers. A utility with a commission-approved least or best cost fuel procurement plan is unlikely to deviate greatly from that plan since any deviation places them at risk of a prudence disallowance. Instead of taking advantage of price differentials among various fuel markets (for example, gas futures, spot gas, short-term gas, or long-term gas), fuel managers tend to stand firm. The ex-ante fuel procurement review tends to substitute for legitimate managerial prerogatives as the utility adheres to the fuel portfolio approved in the ex ante plan.

To overcome these limitations, a fixed-weight method of designing PGAs is proposed to encourage incentive compatibility. The fixed-weight PGAs provide utilities with appropriate incentives to engage in least-cost procurement in competitive markets, while mitigating price signal distortions to the consumers. Further, it also enables a proper allocation of risks between ratepayers and stockholders. Just as the prudence test provides a proper allocation of risks, when properly applied, a fixed-weight PGA allocates systematic, uncontrollable market risks to the ratepayers. Controllable, idiosyncratic risks are allocated to the stockholders. Thus, a fixed weight PGA has the advantage of being an incentive-based mechanism designed to achieve traditional regulatory objectives, but at a lower cost than traditional regulation.

The fixed-weight PGA also has the advantage of putting fuel procurement decisions and responsibilities back in the hands of the utility manager. It offers them great flexibility to deal with price changes that might occur, not only on a month-by- month basis but on a real time basis. This flexibility is particularly useful as competition becomes more important in setting fuel prices, which is evidenced by a developing emissions allowance trading market, an active gas futures market, and other developments concerning wholesale power purchases.

Here is how a fixed-weight PGA works. LDCs have more supply options today than in the past. Besides the traditional long-term gas market, there are growing spot, forward, and futures markets. LDCs can now buy gas directly from producers or indirectly from brokers. The fixed-weight PGA uses two classes of weights: market weights and supplier weights. The market weights measure the contribution of each market-long-term, forward, spot and futures~to the total supply portfolio. Consequently, the weights are proportions that add up to one. A supplier's weight measures that supplier's contribution to a particular market supply. Suppose, for simplicity, there are only two market classifications: long-term and short-term markets. Assume initially the LDC purchases one-half its supplies from each market employing the market weights .5 and .5 respectively. Within each market are suppliers. For example, the long-term market may have two suppliers, A and B, supplying 70 percent and 30 percent, making the supplier weights .7 and .3, respectively. The market weights (.5, .5) add up to one as do the supplier weights within a market (.7, .3). Supplier A's contribution to the total supply is given as the product (.5) X (.7) = 35 percent. The weighted cost of gas (WCOG) is simply computed as a weighted average cost of the different sources of gas supplies. In addition to A and B, suppose Suppliers C and D supply .6 and .4 of the short-term supplies. Furthermore suppose the $/Mcf for suppliers A through D are $3.00, $2.80, $2.20, and $2.10. Then the WCOG = .5 [(.7)($3.00) + (.3)($2.80)] + .5 [(.6)($2.20) + (.4)($2.10)] = $2.55/Mcf.

Once the market and supplier weights are set jointly by the commission and the LDC, the LDC can make any purchase decision it chooses; it is not restricted to purchase according to the fixed weights (the WCOG). As prices for gas supplies fluctuate, the LDC can purchase supplies in relative quantities that differ from those incorporated in the fixed-weight PGA, allowing the actual cost of gas (ACOG) to deviate from the WCOG. But, to encourage efficiency, LDCs must permanently retain a share of the cost savings from seeking the efficient gas portfolio.

The basic incentive mechanism behind the fixed-weight PGA is setting a supply portfolio target and providing the LDC with an incentive to outperform the target. The incentive mechanism allows both the ratepayer and utility to share the cost savings from optimal decisionmaking. The target is the WCOG determined by the predetermined fixed weights and actual prices. As fuel prices change the target changes to reflect the current market realities. For example, should the price of supplier C rise to $2.40/Mcf, then WCOG would be valued at $2.61/Mcf. The fixed weights become suboptimal, whenever prices fail to change proportionally, that is, there exists a lower-cost portfolio offering the same level of reliability.4 Say, for example, the LDC responds by purchasing 60 percent of its short term supplies from supplier D and lowers to 40 percent amounts purchased from C. In other words, suppose the supplier weights change from (.6, .4) to (.4, .6). The actual cost of gas (ACOG) becomes: ACOG = .5[(.7)($3.00) + (.3)($2.80)] + .5[(.4)($2.40) + (.6)($2.10)] = $2.58/Mcf.

The retail cost of gas (RCOG), the cost charged to ratepayers, is neither the actual cost of gas (ACOG) nor the weighted cost of gas (WCOG), but rather lies in between. Its exact position depends on the sharing rule (s), that is, the amount the utility permanently retains. Its formula is as follows:

RCOG = ACOG + s(WCOG - ACOG).

* A discussion of use of a Reliability-Price Index and a Consumer Welfare Index to account for reliability differences in fuel markets is contained in Burns, Eifert, and Nagler, 194-198. The retail gas cost, that is the base cost to ratepayers, equals the actual cost plus the share, s, of cost savings kept by the LDC. The authors believe that it is desirable for s to be set high enough to have a significant effect on the utility's behavior, but that it is politically unrealistic to expect s > .5. The final term of the formula measures the profit to the LDC for reducing supply cost, and therefore, is the incentive mechanism in the fixed-weight PGA. By setting s equal to .5, the RCOG = $2.58 + .5($2.61 - $2.58) = $2.595/Mcf. The LDC earns ($.015/Mcf)(quantity purchased) in profits and ratepayers benefit by paying $2.595/Mcf rather than $2.61/Mcf that they would have had the LDC been passive and failed to adjust its portfolio to reflect price changes.

Conclusion

Other incentive-based mechanisms have been suggested at this conference. However, they are fundamentally flawed. The proposal that the best method of achieving maximum benefit from competitive natural gas markets is to have state public service commissions preapprove the composition of gas procurement portfolios would shift market risk from the utility to the consumer. In addition, the resulting reduction in regulatory risk would require a commensurate decrease in the utility's rate of return on equity. Further, there is an insufficient incentive for the utility to minimize its costs. The proponents of preapproval themselves acknowledge that portfolio preapproval and least- cost bidding are imperfect methods for replicating the price discipline that competition creates. Indeed, regulatory preapproval of contracts tends to stifle competition.

The proposal that the spot price of gas be used as the sole benchmark against which the prudence of all gas purchases are judged fails to take into account the value of reliability that LDCs may place on gas, particularly for core customers. Because of its obligation to serve, the LDC must assure that these customers have reliable service, especially during extreme weather. Reliability has value.

Fir illy, the suggestion that we should experiment with price cap regulation is naive. Price cap regulation may be an option in a multiproduct market, with a mixture of competitive and noncompetitive services. Natural gas, however, is a commodity, a fungible product. While delivery and storage of natural gas may involve services that can be differentiated, providing for price cap regulation in the natural gas market in the "hopes" thax Ramsey pricing would result seems to invite undue price discrimination. Traditionally, most consider undue price discrimination to violate sound regulatory principles.

Our proposed fixed-weight PGA, on the other hand, provides state commissions with the appropriate conceptual model on which appropriately redesigned PGAs could be based. The fixed-weight method is introduced as a framework for the recovery of costs which now flow through state PGAs. The method can potentially foster long-standing regulatory objectives in an environment where competition has become more prevalent. For example, it automatically allocates risks appropriately between ratepayers and shareholders, with ratepayers bearing the uncontrollable, systematic market risks, and the utility bearing controllable, utility-specific risks. Further, it provides LDCs with the proper incentives to minimize cost, while assuring an appropriate degree of reliability, in a more open and competitive gas market.

>;'_; ' NATURAL GAS DISTRIBUTION COSTS AND EFFICIENCY IMPLICATIONS FOR REGULATION

Mary Lashley Barcelia, Ph.D.

Presented at. the DOE/NARUC National Conference on Natural Gas Use New Orleans, Louisiana April 27, 1993

EXECUTIVE SUMMARY

This paper describes the results of a comprehensive economic analysis of natural gas distribution costs. The analysis was based on data from fifty local gas distribution companies covering the period 1969-1988. It shows how total costs of gas distribu- tion are related to the types of markets served and to the prices of gas, labor and capital purchased by the companies.

The methodology has a broad application. It can be struc- tured to evaluate the cost impacts of different load structures and can derive specific cost estimates for any actual or hypothet- ical firm. It can be used to estimate marginal and stand-alone costs of service, to evaluate the cost impacts of load loss or gain, and to measure the relative cost efficiencies of individual firms.

Major findings of the study are:

1. Natural gas distribution is a natural monopoly with strong economies of scale and economies of scope in serving different types of markets (residential/commercial, firm industrial/elec- tric, interruptible, and wholesale). Therefore, continued

, 1 regulation of gas distribution can be justified on natural monopoly grounds. This does not necessarily mean that unbundling of gas sales from gas distribution is unjustified. For example, if gas distri- bution achieves its most efficient scale at the local or regional level while gas marketing is most efficient on a national scale, the unbundling of distribution from sales could be justified, as long as provision were made to deal appropriately with the natural monopoly characteristics of each activity.

2. For an LDC that enjoys economies of scope from serving a diversified market, the loss of firm industrial/electric or interruptible customers to bypass, fuel-switching or business failure can significantly increase the cost of service to remaining customers. Within limits, if rates can be restructured to prevent such load loss, the remaining customers will be better off than if the load loss takes place. The cost function can be used to determine the limits of such a rate restructuring.

3. Long run marginal costs are significantly lower, and stand- alone costs are significantly higher, than average costs in each market sector. This is to be expected in an industry character- ized by economies of scale and scope.

4. Large firms tend to be less efficient than small firms. More over, the degree of inefficiency is such that it almost exactly

547 offsets the benefits of scale economies. In other words, as firm

size increases, economies of scale cause average costs to decline

while at the same time costs are increased by growing inefficien-

cy. The result is an approximately constant average cost curve.

This finding is important for a number of reasons. First, it

indicates that studies that find constant average costs in an

industry (and therefore conclude that no scale economies exist)

may actually be measuring the combined effect of cost-reaucing

economies of scale together with cost-increasing inefficiencies.

Policy recommendations to deregulate an industry on the basis of

such

Second, these results support criticisms of cost-of-service

regulation as promoting inefficiency. Some form of alternative

(incentive) regulation is clearly called for. However, incentive

rate regulation, if adopted, should take into account existing

levels of inefficiency. For example, price caps might be set

lower for firms whose costs include high embedded inefficiencies.

And yardstick regulation, which bases rates on industry-wide costs, might be considered altogether inappropriate if industry- wide costs contain significant inefficiencies.

Finally, the acknowledgement of inefficiencies in an LDC' s costs and the development of regulatory and management strategies to reduce these inefficiencies can enable firms to meet bypass threats, enlarge their markets, and in general operate more effec- tively in the increasingly competitive gas market that is emerging

in the United States.

••-•'5 3 INTRODUCTION

During the 1970s and 1980s, the deregulation of the airline,

trucking and railroad industries was greatly aided by the develop-

ment of techniques for the economic analysis of industry costs.

These techniques allowed the investigation of regulatory issues

such as whether an industry really is a natural monopoly, whether

continued regulation is in the public interest, the likely config-

uration of the industry after deregulation, how to allocate joint

costs, and how to estimatf long run marginal costs needed for the

efficient pricing of outputs.

All of these issues are of recent and current concern to the

natural gas transmission and distribution industries. Curiously,

however, the economic analysis of industry costs, which proved so

valuable in deregulating other industries, has been largely absent

from deliberations over natural gas regulation at the federal and

state levels. For example, FERC Order 636 unbundled gas pipeline

services, requiring pipelines to offer gas sales, transportation

and storage as separate products, without first investigating the

,ost structure of the industry to determine whether economies of

scope exist among these products, thus making it less costly to

provide them jointly than separately. At the state level, the

California Public Utility Commission's recent ruling establishing

techniques for determining long run marginal cost is based on a cost-of-service accounting approach, which allocates (sometimes arbitrarily and often controversiaily) specific categories of

costs to specific categories of customer demands that are classi-

fied as marginal. A more straightforward derivation of marginal

costs can be obtained from the economic analysis presented in this

paper.

This analysis was based on data from 50 local gas distribu-

tion companies (LDCs) covering the period 1969-1988. It shows how

total costs of gas distribution are related to the types of mar-

kets served and to the prices of inputs purchased by the compa-

nies. These results can be used by regulators and company manage-

ment" to determine marginal costs of service, to evaluate bypass

issue.', and to confirm whether natural gas distribution is a natu-

ral monopoly in need of continued regulation. Finally, the metho- dology yields estimates of firm efficiency, which allows a ranking of firms from most efficient to least efficient and which permits analysis of the sources of inefficiency.

NATURAL GAS DISTRIBUTION COSTS

Gas distribution costs depend on the types of markets served

(i.e., the load profile) and the cost of inputs. The analysis can be structured to evaluate any load structure for which data are available. For this particular analysis, three retail sectovs and one wholesale sector were designated:

- Firm residential/commercial sales

- Firm industrial/powerplant sales

- Interruptible sales - Sales for resale and three inputs were specified. - capital - natural gas - labor In addition, service area density (customers per square mile) was included in the analysis, but found to have no net impact on costs. (Presumably, the cost advantages of a densely populated service area were offset by higher land, congestion and regulatory costs. ) The analysis can be centered around any actual or hypotheti- cal firm, giving specific cost estimates for that firm. The re- sults presented here pertain to a hypothetical firm whose output quantities and input costs are the average for the fifty firms in the sample. The characteristics of this "average" LDC are given in Table 1. It had residential/commercial sales of 54.9 trillion Btus (TBtu), firm industrial/powerplant sales of 21.0 TBtu, inter- ruptible sales of 16.0 TBtu and sales for resale of 2.0 TBtu. It paid an average wage of $34,870 (constant 1990 $), paid $3.04 per mmBtu (constant 1990 $) for gas, and incurred a capital cost of $19.83 (1990 $) per unit of capital employed. Its service area contained 395 customers per square mile. The total cost of ser- vice estimated for this LDC was $408 million (1990 $) for an aver- age cost of $4.35/mmBtu. (By way of reference, the average retail price for all LDCs in 1990 was $4.59/mmBtu). Table 1. Description of the "Average" LDC

Residential/Commercial Sales 54.9 (trillion Btus) Firm Industrial/Powerplant Sales 21.0 (trillion Btus) Interruptible Sales 16.0 (trillion Btus) Wholesale Sales 2.0 (trillion Btus) Labor Price $34,870 (1990 $ per employee) Gas Price $ 3.04 (1990 $ per mmBtu) Capital Price $19.83 (1990 $ per unit of capital) Density 395 (customers per square mile) Total Cost of Service $408.4 (million 1990 $) Average Cost of Service $ 4.35 (1990 $ per mmBtu)

With respect to the impact of market structure on costs, the results indicate that overall costs increase by 0.40% for every 1% increase in residential/commercial sales, by 0.12% for every 1% increase in firm industrial/electric sales, by 0.08% for every 1% increase in interruptible sales, and imperceptibly for increases in wholesale sales. (See Table 2.) Table 2. Impact of Market Structure on Cost of Service

A 1% increase in: increases costs by:

Residential/Commercial 0.400% Sales Firm Industrial/Powerplant 0.117% Sales Interruptible Sales 0.083%

Clearly, costs are most highly affected by sales to residen- tial/commercial customers. However, in all cases total costs increase by much less than the increase in output, which indicates the presence of significant economies of scale. Economies of scale also exist for each product individually. Economies of scope across the four end-use sectors exist when firms serving a diversified load have lower costs than those serv- ing fewer sectors. For the "average" LDC in this example, econo- mies of scope result in a cost saving of 38% compared to the cost of serving each sector with a separate LDC. Since there are pro- duct-specific economies of scale as well as economies of scope, we may conclude that natural gas distribution is a natural monopoly and regulation is appropriate.

CALCULATION OF MARGINAL AND STAND-ALONE COSTS Long run marginal costs can be derived directly from the estimated cost function, as can the stand-alone costs of serving each sector separately. For the "average" LDC, marginal and stand-alone costs for the four markets are given in Table 3. The table shows that the mar, inal cost of residential/commercial ser- vice is an estimated $2.98 per mmBtu, compared to $2.27 for firm industrial/electric utility service, $2.11 for interruptible ser- vice and $0,33 for wholesale sales (constant 1990 $). Note that marginal costs in all cases are lower than the systemwide average cost of $4.35, as would be expected in the case of a natural mono- poly.

Table 3. Marginal Costs and Stand-Alone Costs (1990 $ per mmBtu)

Marginal Stand-Alone Cost Cost

Residential/Commercial Sales $2.98 $6.10 Firm Industrial/Powerplant Sales $2.27 $8.36 Interruptible Sales $2.11 $6.48 Wholesale Sales $0.33 $44.36

Stand-alone costs represent the cost of providing the desig- nated level of service to each sector taken individually. For example, if the 54.9 TBtus of residential/commercial sales were provided by a utility with no other markets, the cost would be $6.10/mmBtu. Similarly; if a separate LDC were built to provide 21 TBtus of firm industrial/electric sales, the cost would be S6.36/mmBtu. If only 16 TBtus of interruptible sales were provi- ded, the cost would be $6.48/mmBtu. In every case, stand-alone costs are higher than marginal or average costs, supporting the conclusion that load diversification lowers costs. APPLICATION TO BYPASS These results can be applied directly to estimate the costs of bypass (or fuel-switching or other types of load loss) to a utili- ty's remaining customers. Table 4 illustrates for the example of the "average" LDC faced with the loss of all its interruptible customers. The total ccst of serving ail four markets (prior to bypass) is $408.4 million (constant 1990 $) for 93.9 TBtus of gas sales, giving an average cost of $4.35 per mmBtu. At this average cost, the total cost of the 77.9 TBtus of non-interruptible load is $338.8 million. If the LDC were to lose all its interruptible load, the total cost of the 77.9 TBtus of non-interruptible load would rise to $380.6 million -- an increase of $41.7 million -- giving an average cost of $4.89 per mniBtu.

Table 4. Estimated Cost Impacts of Bypass

Total Average Cost Cost (mill ion (1990 $ 1990 $) per mmBtu)

Cost of Serving All $ 408.4 $ 4.35 Four Sectors Cost of Serving 77.9 TBtus of Non-Interruptible Load Before Bypass $ 338.8 $ 4.35 After Bypass $ 380.6 $ 4.89

10 In other words, the loss of 16 TBtus of interruptible gas

sales would increase costs to the remaining customers by more than

$41 million, or $2.61 for each mmBtu of lost load. Remaining customers would be better off if rates could be restructured so as to reduce interruptible rates by as much as $2.61 per mmBtu if such a restructuring enabled the LDC to retain its interruptible load.

EFFICIENCY OF LDCs

Cost-of-service regulation has been widely criticized for failing to provide incentives to minimize costs. Roger Sherman suggests that

[since] the firm's own costs are used to determine its revenues, ... an inefficient firm may simply be allowed higher prices and more revenues to cover its higher costs.

Daniel Spulber concurs:

Cost-based pricing may create the wrong incentives for firms. If prices allocate total costs, the firm may not have an incentive to minimize total costs. Regulated firms may not select the best technology, or they may not choose efficient input levels. Cost-based pricing may distort input choices. Average cost pricing in the natural gas utility industry may have been responsible for utility purchases of costly gas supplies that were priced significantly above average market prices in the period following partial decon- trol.

The Regulation of Monopoly. (NY: Cambridge University Press 1989) . Regulation and Markets (Cambridge, MA: The MIT Press, 1989). The results of this analysis indicate a wide range of effi- ciency among LDCs. The second most efficient firm had costs 95% higher than those of the most efficient firm, after taking into account firm differences in output quantities, input prices and density. The least efficient firm had costs 296% higher than those of the most efficient firm. Out of the entire sample, 35 firms had costs estimated to be more than three times those of the most efficient firm, and 13 had costs estimated at two to three times as great.

A primary explanation for the variation in firm efficiency measures is firm size. Large firms tend to be less efficient than small firms. Moreover, the extent of the inefficiency is such that it almost exactly offsets the economies of scale enjoyed by larger firms. This result raises the possibility that the indus- try may not actually experience declining average costs, even though there are strongly increasing returns to scale for effi- cient firms.

Specific causes of inefficiency were not investigated for this analysis. Possible explanations might include inefficiency on the part of firm management, overcapitalization induced by rate-of-return regulation (the Averch-Johnson effect), the pursuit of equity considerations by regulators at the expense of efficien- cy (e.g., enforcing the obligation to serve markets that are not cost-effective), regulators' dependence on firms for information regarding costs, and a pervasive failure of regulators to expect

: . . 12 average costs to decline as the size of the (naturally monopolis- tic) firm increases.

CONCLUSIONS This analysis suggests four broad conclusions of interest to natural gas distribution companies and their regulators:

1. Natural gas distribution is a natural monopoly with strong economies of scale £;nd economies of scope in serving different types of markets (residential/commercial, firm industrial/elec- tric, interruptible, and wholesale). Therefore, continued regula- tion of gas distribution can be justified on natural monopoly grounds.

This does not necessarily mean that unbundling of gas sales from gas distribution is unjustified, however. For example, if gas distribution achieves its most efficient scale at the local or regional level while gas marketing is most efficient on a national level, then the unbundling of distribution from sales might be appropriate, as long as provision were made to deal with the natu- ral monopoly characteristics of each activity.

It should be noted that part of the "inefficiency" may not be inefficiency at all, but a higher (and more costly) quality of service. For example, if reliability of service is greater for large firms, that effect would be measured here as inefficiency, since the analysis does not distinguish different levels of ser- vice reliability. 2. For an LDC that enjoys economies of scope from serving a diversified market, the loss of firm industrial/electric or interruptible customers to bypass, fuel-switching or business failure can significantly increase the cost of service to remaining customers. Within limits, if rates can be restructured to prevent such load loss, the remaining customers will be better off than if the load loss takes place. The cost function can be used to determine the limits of such a rate restructuring.

3. Long run marginal costs and stand-alone costs can be derived directly from the cost analysis. Long-run marginal costs are significantly lower, *iiid stand-alone costs significantly higher, than average costs in each market sector. This is to be expected in an industry characterized by economies of scale and scope.

4. Large firms tend to be less efficient than small firms. More over, the degree of inefficiency is such that it almost exactly offsets the benefits of scale economies. In other words, as firm size increases, economies of scale cause average costs to decline while at the same time costs are increased by growing inefficien- cy. The result is an approximately constant average cost curve. This finding is important for a number of reasons. First, it indicates that studies that find constant average costs in an industry (and therefore conclude that no scale economies exist) may actually be measuring the combined effect of cost-reducing economies of scale together with cost-increasing inefficiencies.

55W Policy recommendations to deregulate an industry on the basis of such a finding would be mistaken. Second, these results support criticisms of cost-of-service regulation as promoting inefficiency. Some form of alternative (incentive) regulation is clearly called for. However, incentive rate regulation, if adopted, should take into account existing levels of inefficiency. For example, price caps might be set lower for firms whose costs include high embedded inefficiencies. And yardstick regulation, which bases rates on industry-wide costs, might be considered altogether inappropriate if industry- wide costs contain significant inefficiencies. Finally, the acknowledgement of inefficiencies in an LDC's costs and the development of regulatory and management strategies to reduce these inefficiencies can enable firms to meet bypass threats, enlarge their markets, and in general operate more effec- tively in the increasingly competitive gas market that is emerging in the United States. Remarks by William F. Whitsitt Vice President, Marketing and Public Affairs Oryx Energy Company for the DOE/NARUC National Conference on Natural Gas April 27, 1993

I'm pleased to be a part of this very important dialogue among natural gas consumers, transporters, producers and policymakers. It is essential to work together if natural gas is to fulfill its potential to meet America's energy needs as an environmentally preferable, abundant and domestically produced fuel. On a more personal note, as an individual consumer I have an interest in natural gas. Because of its environmental benefits I'm glad that I heat my home with natural gas and even drive a compressed gas-fueled car. And I know that an increasing number of Americans are conscious of environmental factors in their energy use and decisions. And they recognize the environmental benefits of natural gas. Because natural gas is such an environmentally beneficial fuel it is of growing interest to state regulators, who must take into consideration the environmental consequences of the fuels used by utilities they regulate. For that reason I would like to focus my comments today primarily on two state initiatives that can promote the use of natural gas: seasonal burning of gas to control ozone; and, encouraging new electric utilities to burn more natural gas to decrease overall pollution. But using more natural gas is not the entire environmental picture. Before I discuss ways you can help your state solve its environmental problems by using more natural gas, let me review briefly some of the environmental realities of natural gas production. Natural Gas Production and the Environment Natural gas resources are abundant. 6,} years of resources in the lower 48 states. 100 years of resources if we include Alaska and Canada. Proved reserves — what we can get to quickly -- are holding steady. An 8-year inventory. A slight dip in the last two years resulted from extremely low prices. The oversupply situation in the industry that led to these low prices appears to be ending. There are signs that drilling activity will increase over the next several years.

Prices will probably rise, but not excessively.

When adjusted for inflation, natural gas prices at the wellhead are only half of what they were in 1984, the last full year of wellhead price regulation.

Consumers pay significantly less per BTU for gas than for oil.

Because so many industries have fuel-switching capability, there is an automatic cap on the price of natural gas. It has to compete with oil and coal for its share of the energy mix.

There is a second cap on the price of natural gas — the price of liquified natural gas that could be imported from the enormous supply of resources in the former Soviet Union and the Middle East.

But having the gas in the ground may not mean that it is completely available to help the U.S. address its environmental problems. Currently, we see many environmental groups promoting gas on the demand side but opposing new exploration and production.

The areas with the largest potential gas reserves that are the least expensive to produce are offshore, and on federal lands. If we are shut out of these prime areas, your ratepayers will pay more for natural gas.

You might be willing to accept that if there were real environmental benefits. But in many cases there aren't. There are no serious environmental hazards connected with offshore or even wetlands gas wells. The impact on federal lands is very minimal. Energy producers today value the environment. The practices today are not those of 30 > 10, or even 5 years ago. We at Oryx Energy are proud of the environment principles we work by — and copies are available at the rear of the room, or I'll be glad to send you one.

All of us have a stake in responsibly meeting challenges to natural gas exploration and production posed in large measure by misperception of industry values and priorities — but I'd really like to focus more today on state-oriented natural gas use isssuss.

Seasonal Use of Natural Gas to Reduce Ozone Emissions

Under the Clean Air Act, states not meeting federal targets for ozone levels must submit control plans. Hearings are now taking place to develop those plans.

Electric utilities are a primary focus of ozone attention.

Ozone results in part from nitrogen oxide emissions.

Half of NOX comes from cars - states can't do much more to reduce these emissions than they already do — certainly not in the short run. Also, voter revolts may result from attacking cars. There are two ways to reduce NOX omissions from coal-fired plants:

Mix natural gas with coal ("reburn" and "co-firing"). By using 15-20 percent natural gas, you can reduce NOX emissions from coal plants by 50-70 percent.

Substitute natural gas for coal, resulting in a 95 percent NOX emissions drop.

However, there are barriers to substitution of natural gas for coal if you need more reduction than you can get from reburning and co-firing.

Demand varies. High demand during the winter heating season creates higher prices and more competition for supply. Much lower demand in summer — prices lower, supply readily available.

Weather conditions can affect natural gas delivery, and on-site storage is generally limited,

Utilities have many sunk costs in coal technology that they want to recover.

A solution: since ozone is primarily a summer problem, burn natural gas in the summer and coal in the winter. A win-win situation:

Producers would be very happy to increase the summer market.

There's no competition with residential heating.

Your meet your ozone requirements.

Companies can still recover their investments in coal.

There is a problem, however: current federal policies. The Environmental Protection Agency appears to have a policy of "continuous control". That means, that once a pollution control is put into place, it must be used all the time.

The "continuous control" policy makes sense in some cases. Public policy leaders did not want situations to develop in which a coal piant, for instance, might turn off its scrubber on a windy day, when weather patterns scatter its emissions widely, then turn it on when still air concentrates emissions in the local area.

But seasonal burn is different. The control measure is being employed continuously over a term-certain of several months. This is particularly appropriate for ozone control.

The EPA is considering changing its policy in response to state input — and I hope there will be more of it.

If the policy changes, seasonal burn strategies could aiso be used to address air quality problems from other pollutants such as sulfur dioxides an particulate matter.

For those of you from states where gas and electrical utilities are linked, there's even further benefit. The two utilities may be able to contract together for firm year-round supplies and pipeline delivery capacity, then share them according to

.'•:,> seasonal demand. If demand outstrips supply at one of the two utilities, the other could reduce demand to compensate. Such a strategy is a cost-competitive approach to risk reduction. The bottom line is that gas can be an important part of creative solutions to energy and environment problems. I'd like to turn now to a more general, and extremely important topic. Environmental Externalities There is a push in many states to switch to natural gas for electrical generation because natural gas has fewer societal costs — generally called "externalities" -- than do fuels like oil and coal. Most work on externalities is being done in the context of state Integrated Resource Planning (IRP) requirements. As we all know, methods for evaluating externalities vary widely and are very difficult. One method is the direct valuation of damage costs. This depends on the transport and transformation of pollutants from their source to the affected area, the exposure within the area, the damages caused, and the values placed on these damages. This direct valuation process is very difficult to quantify. The indirect method is an alternative. Experts are polled to determine the cost of removing the pollutant. This cost is then added to the direct generation costs for each fuel choice to determine the social costs. Methodology isn't the only problem public officials encounter when they try to choose fuels based on externalities. A second question is: Which externalities are important. Some states include the impact of a fuei's use on jobs and economic activity. Others don't. Some value only pollutants that have been shown to harm health. Others include so-called greenhouse gases like carbon dioxide. In general, natural gas comes out a winner in externality evaluations. It is clean-burning. Exploration, production and transportation are done under environmentally sound conditions and with very little visual pollution and relatively slight land use. Natural gas does not have the ash and sludge to get rid of, so you don't have the landfill problems you get when you burn coal. Producers believe that the benefits of natural gas should and can lead to a win-win situation for the gas industry and consumers alike. In short, we think we have an excellent product.

But we do see some dangers in the state externality efforts:

In some cases, it seems possible that the costs of reducing pollution can exceed benefits. This happens if all hazards are weighed equally. It also happens if the cost of corrective measures is understated — which is very easy to do given the preliminary state of this art.

A second problem is that costs to address externalities generally will be borne by the citizens within the state establishing the requirements. However, part of the pollution within that statu may be coming from another state. By the same token, benefits may occur to citizens in another state.

A third problem that worries us is the current reaction to environmental problems that have been proposed but not yet proven. Some states; for instance, are responding to pressure from their citizens and including greenhouse gases in their externality equations. Yet responsible scientists disagree about the greenhouse effect. Is it real? If it is real, will it be more harmful or more beneficial" ff it is real, do the costs of reducing it by specific mandated solutions outweigh the benefits of doing so?

Natural gas almost always comes out a winner in states that are including the greenhouse effect in their evaluations. So I'm not expressing reservations because of immediate self-interest. I do think, though, that we all have a long-term self-interest in making sure that we make the right decisions with taxpayer money. Thus, let me just caution you that some people may overreact to current — possibly overblown -- fears.

I certainly want 'o urge you to consider environmental costs when you are involved with public utility fuel decisions. Private corporations and public officials alike have a responsibility to respect and protect our environment, with future generations in mind.

However, the debate on the specifics of externalities is still at an early stage. It is one thing to take general environmental effects into consideration when evaluating fuels for new electricity generating plants. It is quite another to assign concrete values to a partial list of possible pollutants and use that information for long-term decision-making.

In the long run, I also believe that states can view the federal government as a partner in this effort, promoting federal research that will resolve current questions.

In summary, of course there are challenges ahead as regulators consider gas use. As I've noted, current federal policy does not yet allow the flexibility to permit seasonal burning of gas in all cases. Consideration of externalities is an evolving art as well as a developing science, with uncertainties as to whether the environmental benefits of natural gas will be consistently recognized. And, federa* policies regarding access to the sizable natural gas resources offshore and on federal lands may not be in sync with the fact that these resources are being produced in an environmentally sound manner — and will be in the future if policies permit. Meeting policy challenges will permit natural gas to play its potential role as a bridge to a more sustainable energy future while ensuring sustainable economic health for towns, cities and states across the country. Thank you. DOE/NARUC - National Conference on Natural Gas Use Philip H. Fassett 1993 April 27 My name is Phil Fassett and I'm Manager of Business Analysis at Alcoa's Warrick Operations. The views I express Mill be my own and are not necessarily the views of Alcoa or of Warrick Operations. I am the immediate past chairman of INDIEC (Indiana Industrial Energy Consumers) and a past chairman of IEG (Industrial Energy Group)—a group of 100 national corporations whose Energy Managers meet several times per year to discuss energy policy issues. Alcoa is the world's most exciting & innovative aluminum company. Warrick Operations has 3,800 employees involved in the production of primary aluminum, the recycling of used beverage cans, the casting of ingots and the manufacture of sheet products which are made into cans for the beer and beverage industry. We own an integrated bituminous coal strip mine, operated by Peabody Coal Company, which employs 130 Mine Workers. This coal is supplied to Alcoa Generating Corporation (AGO, a subsidiary operated for Alcoa by Southern Indiana Gas and Electric Company (Sigeco) and 200 employees. The AGC assets include three 144 megawatt industrial boilers and 50% of a 300 megawatt utility boiler which we share in ownership with Sigeco. As such, we control 150 megawatts of generation affected under the CAAA and 432 megawatts of potential opt-in generation. A SIP limits our current generation such that we import one-fourth of our coal to blend with our integrated coal. Clean air compliance can be an expensive variable in our business. Unlike most owners of CAAA affected units, Alcoa cannot pass the cost of compliance on to its customer. In North America, electricity is about one-quarter of the cost of making primary aluminum. Our aluminum smelter competes for survival with primary metal from other parts of the world where electricity casts are lower and environmental excellence mav not be a consideration. Our chances of preserving 1,200 jobs associated with primary aluminum in Indiana are enhanced I-f we select the lowest cost solution to clean air. Natural gas co-firing is a key part of that solution at AGC. 1. Background - QRI testing with Radian verified expected results - skeptical management — How can a fuel that costs twice as much as coal reduce my cost? 2. Unit 1 modification in 1992 with funding help from Tenneco 3. Construct common pipeline & facilities anei retrofit one boiler - replace oil ignitors with big diameter gas ignitors - CEMs with automatic peak shaving - change from modeling concept permit - baseline testing - NOx & SDx effects & possible synergy ??? - 9 months - reduced downtime, cleaner boiler, more mwh, reduced NOx, reduced SOx 4; Will convert each of the other 3 units during major outages as we convert to new instrumentation and control 5. Schedule - Spring 94, Spring 95, 1997 Page -2- DOE/NARUC - National Conference on Natural 6as Use Philip H. Fassett 1993 April 27 6. Other benefits - low Q&li, no ash, fuel flexibility, more Indian. coal, possible NQx solution, eliminate violations 7. Reduces the need far coal inventory With the CAAA, President Bush and the U.S. Congress presented a cost-effective solution to environmental improvement. The Acid Rain program will remove 10 million tons of SD3 from the nations upper atmosphere each year. The allowance permitting process and the opt-in provisions of the act were intended to let the free market help this 40"/ reduction occur at minimum cost to ratepayers.

Most PUCs want compliance to be the least net cost to ratepayers. Net cost considers lost mine worker jobs and considers lost commerce from high utility rates. State legislative actions and other political activity may make achieving least cost compliance difficult. Natural gas ca-firing and emission allowances are two solutions that offer lower cost and avoid the political concerns of disrupting mineworker jobs. Listed below are the strengths and weaknesses of three common solutions.

1 - SCRUBBERS WEAKNESSES - High capital investment - High operating costs - High energy use - High risk of selling allowances at economical prices - Significant solid waste that may have high disposal cost - Increased C0a generation - Very low flexibility STRENGTHS - May allow use cf current coal source - May allow savings by switching to lower cast high sulfur coal - Proven technology

FUEL- BUENDING (INCLUDING CO—F=~ I RE >

WEAKNESSES - Adjusts existing fuel source (minimized by ca—firing) - May require changes to boiler (minimized by co-firing) - Usually higher cost fuel

STRENGTHS - Low capital investment - No or low increase in operating cost - No extra pollution or energy required - Low risk - High flexibility for future technology improvement Page -3- DOE/NARUC - National Conference on Natural Gas Use Philip H. Fassett 1993 April 27

3:. EMISSION ALLOWANCES

WEAKNESSES - Uncertainty in PUC ratemaking

STRENGTHS - Allows use of current coal source - Na capital investment - No increased operating cost or increased fuel cost - No extra pollution or energy required - High flexibility for future technology or fuel blend - COST CAN BE 100% CERTAIN

SOME IMPORTANT CONSIDERATIONS 1. Gas is not always more expensive than coal. 2. Gas can burn in bailers burning coal with minimal modification. 3. Gas reserves and gas transportation are abundant in North America. 4. Allowances selling prices are limited by both the free market cost of reducing emissions and by allowance availability. An enormous over—compliance is taking place and most experts see no hope that selling prices will ever reach $400/ton. 5. Cost effective and environmentally benign scrubbing technologies will soon be commercialized. Gas and allowances can be high flexibility temporary solutions. 6. Federal laws will soon require reduced N0M, C0a or toxics. 7. Local health standards are unaffected by buying allowances. 8. CAAA does not mandates emission reductions for particular units. It simply requires certain affected units to have one allowance for each ton of SQa emitted. 9. Conventional scrubbing is a high risk solution to the CAAA. 10. Natural gas co-firing is not.

Philip H. Fassett

• •.,.» USE OF INNOVATIVE ADMINISTRATIVE PROCEDURES TO CUT THE GORDIAN KNOT: STATE PSC POLICY-MAKING FOR MORE COMPETITIVE GAS MARKETS

Robert E. Burns, Esq.1 Senior Research Specialist The National Regulatory Research Institute 1080 Carmack Road Columbus, ONo 43210

Historically federal and state public utility commissions have relied heavily on adjudicatory procedures to make industry-wide policy decisions.2 State PUCs were among the first to use trial-type proceedings for ratemaking and related matters, which was appropriate for PUC ratemaking because the determination of a revenue requirement, even in states with a future test year, relies heavily on a historical test year. Adjudicatory procedures have proven themselves, both in court and administrative cases, to be well-suited for a retrospective determination of the facts.

However, many of the issue that face state and federal regulators today are basic, industry-wide policy issues that implicitly or explicitly require the agency to make economic and financial decision about future events and conditions and to engage in regulatory planning or policy making based on these decisions. To meet this need, regulatory agencies need to become more progressive, economic regulatory and planning bodies geared toward promoting efficient policy that fit into the broader economic system.

Adjudicatory procedures are, however, cumbersome vehicles to address progressive policy issues, because an agency's decision is limited to the record as presented by the parties. It also causes an agency to be passive and reactive, to respond to the pressures of the parities, and to fail to define its own agenda and fully exercise its power. Further, adjudicatory procedures are limited in their ability to take into account economic and financial issues in the face of uncertainty.

1 The views and ideas contained herein are the author's and do not necessarily reflect those of the National Regulatory Research Institute, The Ohio State University, the National Association of Regulatory Utility Commissioners, or its member state and federal public service commissions.

2 Many of the basic procedural ideas contained in this paper were developed in Robert E. Burns, Administrative Procedures for Proactive Regulation (Columbus, Ohio: The National Regulatory Research Institute, 1988). The report goes into greater depth on understanding than contained in this paper.

5,0 Nor does the typical APA/MSAPA informal notice-and-cornment rulemaking solicit the type or quality of information needed. Unsupplemented, it does not provide an opportunity to probe deeply into the reasons for difference between the parties or the assumptions behind the comments. What is needed is a method of building a consensus among the parties to gain a better understanding of the areas of agreement and disagreement among the parities through discussion with agency decisionmakers.

In this particular circumstance, state and federal commissions are faced with a myriad of issues stemming from FERC Orders 436 & 636 and the Energy Policy Act of 1992. These issues have in common a need for state and federal commissions to consider how to regulate in the new more open competitive market environment. State commissions need to view LDCs in a different light.

For example, an LDC might be viewed in terms of being solely a transporter of gas, without any role as a merchant buying and then reselling gas. Another possibility is for state commissions to encourage LDCs to play an active role in the market by pooling its customers' demands and then aggressively seeking out and negotiating new rates. To encourage LDCs to aggressively bargain, a state commission would need to consider how a performance-based incentive mechanism to encourage LDCs to seek out and purchase the lowest cost gas subject to reliability affects. Such a proposal has been presented in the academic forum of this conference. Other options were presented elsewhere in the conference. These include deregulating LDCs, a strategy which will likely result in undesirable effects, such as Ramsey pricing. Another option discussed is using a spot price as a benchmark for the LDC. That option fails to account for the fact that reliability has value. Yet another option proposed would have the state commission decide what the LDCs contract portfolio should look like through an IRP process and then preapproval all such contracts. This smacks of command-and-control and also tends to shift market risks to the ratepayer.

Only through an ADR, consensus-building form of administrative procedure can state commissions eliminate regulatory options that fail to properly align the interests of the ratepayers in lower cost reliable gas with the interests of the LDC to increase profits. And, only through such an ADR process will a performance-based incentive mechanism result. Further, such an ADR process is necessary to keep a performance-based system operating, particularly when it becomes necessary or desirable to reset the benchmark.

State and federal agencies have developed such consensus-building administrative procedures, many of which use one or more of the alternative dispute resolution methods of mediation, negotiation, and arbitration to achieve their end. Yet, these alternative procedures go beyond what is traditionally understood as ADR by providing decisionmakers with additional means of engaging in an administrative process. One such example is negotiate rulemaking, where a negotiation process is followed by the more traditional notice-and-comment rulemaking. Another such process is the use of a joint problem-solving workshop (often called the collaborative process). It varies from a negotiated rulemaking in that its purpose is to solve a problem jointly. This process works best with a facilitator and technical experts representing the major interested parties tackling a problem jointly. Another such process is the use of a task force that brings together all of the major interested parties and groups to recommend a potential

57! solution to a problem. Here too the objective is to form a consensus solution to a problem.

Other processes include the use of advisory committees, and scientific panels or boards of inquiry. By using new and innovative administrative procedures, state and federal commissions are designing the tools needed to decide prospective policy issues that involve economic and financial projections as well as scientific uncertainty.

Of course, a concern that most attorneys will have is whether these procedures can be designed to assure procedural due process in an administrative setting (that is, notice and opportunity to be heard). The NRRI developed eight guidelines for proactive regulation that, if followed, should go a distance toward assuring due process. The eight guidelines are (1) have a rational choice of procedure, (2) issue an initial notice, (3) provide for representation of all interested parties, (4) have the necessary data, (5) have a record or an advisory report, (6) issue a final notice and provide an opportunity to be heard, (4) the board should be the ultimate decision-maker, and (8) announce the policy determination, including its rationale. REGULATORS, THEMSELVES Calvin K. Manshio DOE/NARUC National Conference on Natural Gas Use The Fainnount Hotel, New Orleans, Louisiana April 27, 1993

We are currently undergoing a period of transition in politics, economics and regulation. The end points of which remain uncertain. Public utility regulation can provide a microcosm of these changes and how to deal with them. Like politics and economics, public utilities must adapt to a new reality. For utilities the landscape has become competitive; just as their responses cannot be based on a regulated mentality; regulators need to better reflects market changes in the manner in which they regulate. Even ratepayer expectations have none remained the same. As a result regulators must decide whether they will defer to the expectations manifested by ratepayers or continue to act for ratepayers.

The attitudes of regulators in this transition is important. They can lead, follow, or be overwhelmed by expectations and events.

The time is appropriate for regulators to regain some directional control over the process. Regulators and staff need to do some introspection on the nature and future of regulation, the scope of the new market reality, and the real limitations placed on their own abilities to "regulate."

57: Almost eighty years ago in 1915 Theodore Vail, President of AT&T spoke to the National Association of Railway Commissioners, the predecessor of the National Association of Regulatory Utility Commissioners and proposed that, " Regulatory bodies, state and federal, should be thought of and should think of themselves as juries charged with protecting the individual member of the public against corporate aggression or extortion, and the corporate member of the community against public extortion and aggression.11 To achieve these ends, Vail concluded that "regulators should be men of the highest standard, appointed for life".

Vail's remarks should be seen in their historic context. AT&T had much to gain by promoting a standard philosophy of regulation under univc ,al service. At the same time, Vail's simple remarks provided a philosophical model for public utility regulators.1

The model can be reduced to two fundamental principals. First, regulators should seek an equilibrium, that is act in a manner that balances competing interests; Second, in balancing those interests regulators should set and maintain goals or standards for themselves and the companies they regulate.2

'Manshio, Calvin. "A Framework for Regulatory Decisionmaking." Illinois State Bar Association Public Utilities and Transportation Newsletter. June, 1991, Vol. 26 No. 4 2Nobel Laureate George Stigler believed that over time regulators were captured by the attitude of utilities. That viewpoint has changed so that today's regulators, I believe, is

574 Vail's model for regulation was the "jury" system. Over time, regulators have modified this system into two distinct schools of thought: First, that "jury" really means "judge," and accordingly commissioners only need to make decisions and not worry about policy or consequences. Second, that regulators are really the "police" enforcing the letter of the law against public utilities, who possess the natural tendencies to misbehave. Beth schools of

thought, "judge" and "police" were reinforced bt the economic justification that regulation was a substitute for the absent competitive market. Both schools, I submit are deviations from Vail's idea and Vail's "jury" idea, itself is defective because it did not contemplate the policy setting role of regulators.3

Notwithstanding my opinions on Vail's model and its progeny, the models do provide a framework for discussion on the role of regulation and regulators. No matter what your task at a Public Utility Commission is; How well you do your task is more important than the title. But, how can you do it well if no one knows where overly influenced by public perception and media coverage. Manshio, Calvin. "Lost Opportunities: A New Theory of Capture." Illinois State Bar Association Public Utilities and Transportation Newsletter. Vol. 26, No. 1, September, 1990. 3An elaboration of this viewpoint can be found in articles written by me for Public Utility Fortnightly: "The Realpolitik of Regulation," May 1, 1992 and "Help of Hinderance? Regulators in a Changing World," January 15, 1993. In addition, a forthcoming article "Yesterday Gone: The Risk Associated with Tomorrow's Electric Utility Infrastructure" in Hay, 1993 issue of Management Quarterly, a publication of the National Rural Electric Cooperative Association addresses the problems associated with a utility's obligation to serve in a competitive environment.

575 regulation is headed.

A regulator's job is to solve problems, not just make decisions. And in solving those problems, regulators should be a participant in the process not a mere spectator.

Lest there be any confusion allow me to define a regulatory participant. A regulatory participant is one, who understands the issues; knows the facts; reaches a decision; and can explain his decision. These conclusions sound self-evident. They are not. Many commissions go out of their way to avoid the traditional legal/regulatory framework. As a consequences, courts are unwilling to defer to PUC expertise. Today, many lawyers appealing PUC decisions by beginning their arguments with, "The decision below was an order of the PUC, and there are other reasons why the Court should reverse." Hardly, the professional standard Theodore Vail or most commissioners envision.

Yet this analysis does not fully embrace the problems facing PUCs. The goal of PUCs should be more than reaching "legally sustainable orders." PUC decisions should more importantly provide clear policy direction.

Unlike Vail and his adherents, I believe PUCs must do more than provide an equilibrium. Regulators must set standards for themselves and their utilities by which economic progress is stimulated. The present reality does not speak of or want balance. Consumers want retribution and utilities want out, regulation has b««n allowed to become the first stage of litigation. In this context the attitude of regulators shifts with public opinion. As a result, business circumstances for utilities has suffered and the reality of regulating with less personal and funds has created a death spiral for PUCs.

For its first seventy plus years public utility regulation provided the stability to stimulate economic growth. Happenstance saw capital improvements match economic growth and both steadily moved forward in tandem. This correlation between gross national product and capital construction created a myth that rate base/rate-of-return regulation worked. Actually, regulation worked inspite of itself. Since regulatory decisions were largely incremental, problems could be corrected or modified tc avoid service or financial disaster. In a sense the system ol* regulation reflected the public utility's engineering perspective of building for the long term within the economic pace of the times.

The two schools of thought derived from Vail's jury model, I will refer to as "jury" and "police" enjoyed peaceful coexistence largely because the circumstances did not require hard decisions or firm policy commitments. Regardless of what school of thought you followed the transcending philosophy adopted by both schools argued tor maintaining a regulatory equilibrium was paramount.

57/ The system worked. Economies of scale reduced unit price and PUCs found themselves in the "golden age" of regulation with little to do and less to know. As a consequence few standards were set for. either regulators or public utilities.

Then began the age of "power too cheap to meter," "open access" and divestiture. Regulators were faced with a whole array of problems involving cost, service and competition. Instead of addressing regulation's fundamental framework, PUCs sought to decide for the short-term. As a consequence judicial reversals and legislative actions emerged.

The problem for regulators is really quite similar to that of utilities. Without benchmarks or competition, regulators and public utilities came to believe what they did was correct because they said so. This attitude stems from a lack of market perspective.

The subjective wisdom of a few regulators cannot substitute for the market responses of the many. Break downs in the traditional paradigm of regulation lead to greater public scrutiny and trivialization of complex issues into simple questions. Today, mest cases are reduced to the sole issue of what will it cost consumers.

The saddest consequence was that the resulting shift in regulatory attitude forced decisional focus away from the traditional long term perspective of "what is the problem" and "how can it be solved" to short term solutions for high costs and "whos do we blame." The results af no regulatory policies, changing economics and greater media scrutiny led to a shift in public expectations and a change in regulatory attitudes which has largely destroyed any semblance of balance as a framework for- regulation.

The task for regulators today, is to either restore the sense of balance so they can stimulate economic progress or develop a new framework for economic 'progress that reflects present circumstances. Any attempts to craft a new framework or reinvigorate the old one must include all participants.4 The results may not be "legally" binding, but like the old regulatory bargain a common framework can help all participants reach a decision and not profit from prolonging the process.

As a former regulator, I believe, competition can improve and/or replace regulation. The answer to more competition, however, is not necessary less regulation. The answer really depends upon what goals you are pursuing. Utilities want less regulation, ratepayers want less cost. Given these perspectives how should PUCs regulate? That's something we should be talking about. Like Theodore Vail second point regulators should set goals for themselves and those they regulate. Without setting goals

4Manshio, Calvin. "The Reality of Ethics in Regulation." Proceedings Biennial Regulatory Information Conference. September, 1988. regulation becomes a meaningless act. Deragulatory Dynaiiies: Bypass and Reckoning in the California oas Market

Robert L. Bradley, Jr. President, institute for Energy Research

Prepared for the DOK/NARUC Conference April 27, 1993 New Orleans, Louisiana Daregulatory Dynamics: Bypaaa and Reckoning in tha California Oaa Narfcat by Robert L. Bradley, Jr. Abstract Competitive developments in the California gas market are forcing the California Public Utilities Commission (CPUC) to abandon rate penalization and heavy-handed regulation of noncore gas transportation. The noncore market includes industrial, enhanced oil recovery, and electric generation customers in the state. This paper describes: 1) how pipeline-to-pipeline competition in California, first proposed in the early 1960s, finally overcame regulatory obstacles and began in 1992; 2) how California went from a capacity-constrained market to the most overbuilt interstate pipeline market in the U.S.; 3) the current regulatory predicament created by state and federal regulation that unintentionally promoted bypass and stranded investment from excess capacity; 4) the new policy initiatives of the CPUC to address the current predicament; and 5) the growing chorus of regulatory reformers outside of the CPUC. California gas regulation is at a crossroads. Either the current regulatory framework is finetuned through pragmatic adjustments or fundamentally revamped through appropriate legislative and administrative reforms. This paper argues for fundamental reform and explores the case for: 1) completely deregulating the noncore market in California; and 2) introducing a deregulatory dynanic in the core market by empowering consumers to self-organize and privately contract to bypass rate-inflating CPUC regulation.

5S.i DOEWARUC National Confereacc oo Natuntl Gu Use STATE REGULATION AND MARKET DYNAMICS IN THE POST £WENERGY POLICY ACT EBA New Orleans April 27,1993

INDUSTRIAL MARKETS: TRYING TO ADAPT TO LIFE UNDER ORDER 636

Outline of Remarks of ANDREW S. MERRELS Energy and Purchasing Consultant OWENS-CORNING FIBERGLAS CORPORATION and CHAIRMAN, PROCESS GAS CONSUMERS GROUP

Introduction

A. Announced purpose of conference is to examine topical issues about (a) the market potential for natural gas and (b) the impact of State regulation on gas use.

B. Industry and regulators must give more than Up service to the fact that these issues an interdependent

n. State Commission and LDC Reactions to the Department of Energy's Notice of Inquiry Concerning State Gas Regulation

A. "Get off our turf!"

B. "Everything's just fine."

C "We'll handle things when the right time comes."

D. Things are different at the state level because LDCs have an 'obligation to

TH. State Commission and LDC Reactions to Order 636 and Pipeline Restructuring Proceedings at FERC

A. There won't be anything left to decide once FERC finishes its agenda."

B. "All that's really changed at the state level is that closer attention must be given to LDC purchasing decisions."

C. "Above all else, LDC loads must be protected." DOE/NARCC Coafcnaa April 27,1M3

IV. TTsfc Way Industrial Gas Consumers See It* DOE'S Notice of Inquiry and State Regulator Goals

A. Despite all the rocks hurled at it, industrial {as consumers saw DOE'S Notice of Inquiry as an opportunity

(1) to articulate a number of basic principles that an — or, at least, should be — common to the manner in which the natural fas market is regulated throughout the United States;

(2) to identity and analyze potentially promising courses of governmental action (including decisions to nfiuin from acting); and

(3) to identify potentially harmful courses of action and analyze why they should be avoided.

B. Industrial gas consumers urged that the NOI and the considerable resources available to DOE be utilized not to impose any specific mode of regulation on the States, but rather to compile the best available data, analyze it objectively, and provide thoughtful recommendations for State Authorities to consider adopting (and/or adapting) for their own jurisdictions. State regulators, the gas industry, and gas consumers need for DOE'S leadership effort to continue.

State regulatory authorities should be working toward ma'rtmMni the practi- cable implementation of open access, unbundling, and equallty-of-service principles at the State leveL

1. States should adopt policies and regulations that (a) enhance consumer access to LDC distribution systems and (b) eliminate policies that render LDCs the favored (if not monopoly) service providers.

2. State unbundling efforts should be guided by what should be the Golden Rule of utility regulation: aD autamen ifcosdd have access to, and pay for, the facilities and services they actealfy wart; they should not have to pay for services they neither want nor

3. As at the federal level, State equalify-of-service efforts must strive to place alternative gas suppliers in the same merchant and transports* tion positions as the LDC enjoys - without sacrificing reliability of firm services or predictability of interruptible services.

586 Andrew S. Mcm* DOEMARUC OMfcraws April 27,1993

V. Hie Way Industrial Gas Consumers See It: Operating and Regulating LDCs In the Wake of Order 636

A. With only a very few exceptions (eg., Ohio), most state commissions have done next to nothing to prepare for the implementation of Order 636 on the pipelines which directly or indirectly serve their states.

L Order 636 is in effect mow on some pipelines and will be in effect on all others within the next several months. What are you waiting for?!

2. Tne array of services offered by restructured pipelines will be different from those previously available; hen is a chance for LDCs to fill the gaps and add real valat to the Btus they deliver.

3. Consumers in your states are in jeopardy of losing the use of pipeline capacity which may be released by your LDCs. Proactive steps are needed now to meet the needs of your constituents.

B. Many state policies and processes have been dramatically affected by Order 636 and must be reexftmined; state regulators must not assume otherwise. Some such longstanding policies and processes will need to be revised; some will not; but the inquiry auisf be made mow. For example:

1. "TVwuitioa Costs"

a. How should a state commission and the LDCs it regulates help to minimize pipeline transition costs and insure that they are bonafide, prudently incurred, and actually caused by Order 636?

b. How should transition costs be recovered in LDC rates? Should the different types of transition costs be treated differently, Le., recovered from different mixes of customers?

c Should LDC shareholders bear some share of these costs? If not, should they be permitted to share in any of the benefits (alleged to be) associated with these costs?

Capacity ReaUocatiM

a. What roie should a state commission have in determining appropriate conditions on its LDCs' releases of interstate pipe-

3- Aadnmr 8. Mtrnk DOE/NARUC CmtmmuM April 27,1993

line capacity? Should a state commission put limits on the amount of capacity that can be released?

What criteria/conditions should LDCs be allowed — or encou* raged — to impose on capacity releases?

(1) Should state commissions require each LDC to offer any released pipeline capacity first to its own customers before offering that capacity to non-customers? Should an LDCs firm customers (e.g., process and feedstock customers) have priority over its interruptible cust- omers?

(2) Should an LDC be required/allowed to discount its rates for local distribution service in order to facilitate ib customer*:' ability to bid maximum rates for the LDCs released pipeline capacity (thereby pre-empting less attractive bids from non-customers under Order 06)?

(3) How should LDCs' capacity recall rights be structured?

Should pipeline demand charges be unbundled from LDC rates to prevent double-payment by customers obtaining released capacity?

How should demand charge credits or other payments to LDCs for released capacity be flowed through to their customers? What if revenues are lost when excess capacity is not reteassd?

Should self-dealing conditions be permitted (&;., summer peaking or other terms insuring that onfy the LDCs electric generating affiliate qualifies)? Should releases to LDC affiliates be prohibited?

3. LDC Rates

How should a state commission respond to adoption of Straight Fixed/Variable (SFV) rate design at the pipeline level?

How should a state commission respond to pipeline "mitigation measures" adopted as a transition towusd rail implementation of SFV rates? ABtanr&Mamto DO&NARUC CMhnm April 27, l»3

c Should LDC rates be (ftirther) unbundled in recognition of the unbundling of pipeline rates?

4. Operational Matters

a. Do any of the state's current gas transportation provisions need to be changed in light or Order €36?

b. How should scheduling of deliveries be coordinated between LDCs and consumers?

c. Should LDCs be required to make access to pipeline electronic bulletin boards available to those of their customers who lack direct access?

d. Should a state's LDCs be required to coordinate their own elec- tronic bulletin boards with those of any pipelines serving the State?

e. Should balancing service be offered by LDCs behind the city* gate? What other services do the state's consumers need LDCs to provide in the restructured world?

t Should any changes be made to current LDC balancing/sche- duling tolerances and penalties?

g. Should any changes be made to existing nomination provisions in LDC transportation tariffs to be more consistent with pipe- line nomination requirements? Do existing procedures for changing nominations allow consumers to avoid LDC penalties?

h. Should Operational Balancing Agreements be available for LDCs' customers? If so, under what terms?

L Whose gas should be deemed to be first through the city gate meter - the LDCs or its customers'?

j. How should predetermined allocation procedures between pipelines and LDCs work? Will they force LDC customers to bear the consequences of other shippers' imbalances?

-5- Andrew S* Muidi DOE/NARUC Coofcrence April 27,1993

k. Will accurate and timely notice of deliveries and any imbal* aaces be provided to LDC customers? Are existing metering and interconnecting facilities adequate?

L If there is insufficient pipeline no-notice service available for all who want it, should LDCs be required to share some of their allocation with their own customers?

5. Cartaflmeat Policy and Practice

a. Haw should easterner-owned gas be treated by LDCs during curtailment situations?

b. Are changes needed to LDC curtailment plans similar to those needed in pipeline curtailment plans?

c What compensation should there be for customers whose gas or capacity are legitimately appropriated during a curtailment emergency?

6. More General Matters

a. How has the LDCs "service obligation" been affected by Order 636*s restructuring of the gas industry? What changes in regu- lation are suggested by this change in the mature of the market and LDCs' obligation, not to stU, but only to Mbtr.

b. What different or additional service offerings should LDCs develop to meet the needs of their customers in the post-636 world? How can LDCs add value to what they provide their customers?

c If "equality of service" can be achieved at the LDC level, does any reason remain to regulate the LDC merchant function?

VL Conclusion: A Plea for Pro-Active Cooperation - Not Someday, But NOW!

5S;> APR- 2-93 FRI 9:44 NM GAS PLUM STREET FAX NO. 315 480 3006 P. 02 ,.m °'s es'3' •»•<»• S 9*

Em/ltt to Industrial Markets Abstrad of ReBivka to PcneS #19 of the &OE/NARUC National Conference en Natural 6M Use New Orleans, LA April 27, 1993 by Robert J.Patryfo Senior Vice President • Oai Business Unit Niagara. Mohawk Rawer Gaponttan Syneace, New Yodc Niagara Mohawk supports efforts to deregulate Jhe natural rasindustry . Gompeddon has edited in the gas industry tor some dnaaad It Is h«cio»tty. WbUft increased competition can benefit aQ of our customers, transition to more Mly deregulated msrkcts will create winners and losers. - Niagara Mohawk intend; to focus en the opportunities and ba a winner. We've offered onbundleti transportation service for about (even yew sod t form of no notice services far two end one half years. Last year wo wewJfaefim to introduce wp*i^ brokering service in New Ycrt WeptotowoticvmhthebfyS3>al^Scfvi»O()mrnuriontooffw^ expanded mean of additional pa services.»Industrial ctutoroers. We're looking at doing tblt smifl the regulatory framework thereby capturing benefits for die firm ntepayer while nvoidin J the duplication and added expense of an tiuwpendendiiit However baid we want to compete, local distribution oompinla> (LDCt) will not bo able » succeed withoDtUieftUl nipport of dirfr awe itguliuocycomraiwlons. LDCs need rone freedom ind flexibility to respond! to changiDg market conditions and luger inceativei to assume die risks Associated wuh mart competitive mntetts. Any cross subsidies to residential custotoen at die expenai of industrials camtraka LDQ ability to compete iniismoitccntejiedrB>doet>—the mdosoiBl sectsc TnuJltionnl ippn»cnti to wte of rwnmre|ulatloncuj create assynetrical risks andrewaids. Capping profUs at the allowed raw of return, wnDorequlrineLOC to bear tiie downside risk ofnew bmiaess venones, will dampen die fpWQ of even the most enthuilaaic Finally, pi^sciive iir«>lvwnB3t rather than a reactive regiuatory response it needed. We need to offer ssrvicies that are at least comparable to the qpsllty and diversity of offerings of our eompedion. Ibis meant that regulators will be fodog an onsausot of Innovative flexible me designs thai will require pramps action to keep the playiiiE field level for LDCt- WeYestrJving for a collaborative approach with our cuitoons and the Cbxmnissioa «reringfas»r regulatory approvals of our new tariffs. Competitioo has created a aewudom of rtguktion. Iftbenon-core market is going to be repluted, dien i^ulauws wlJl h«ve to oaovc in pace wid» 1« playen. Wj»J>eliRv«-thi>r. niBncjHrfiii|v i^iyjnjtji] jnpre_cpafflgri}>ve nnrictc will requbc lighter handed approaches DO regulation, inclinable more {nceatrve-bssad ntemakiag. We be&eve tbat some toira of uwenrivc regulation coold provide belter incentives to control com awl improve efficiency. WeVe begun testing a the EM dadhution unit cost index st Niagara Mohawk In om-1993 MERIT program with die NYS Public Service Commission, Integrated Rwomce Phuwing and Dewand Side Minngymww can te aompetirive weapam or n create an onlsvel playing field for LDCs. Oai markets are much more competitive dian electric mariceawsre when DSM was initiated, TTiOTlsstiangintaftidcxnnpetidonandtJjeLDCa planning horizon in supply contmednx is dm* to six yean versos 10 to 20 years tor efcetrie resource planoinc. DSM wiD be goodnewi foroa r cmtmnen and ftifly developed 1RP will iccrease LDCs planning flsxfbility. Compcdtlve motets and shorter punning borisons pose DSM lelated rfiiummm; for gjj tjjsi electric otiSliics are only beginning to grapple wiai. Oas is not eleeddty. For example, rcvnioe decoi^ling is not the eniwer to compensating for lower tales volumes. Volumemc Bmt&axgcs applied ID all customers will reduce our ability to compete in key market*. S^DSM^bd^dhtidhf^^pgmgppiy h possible. Where it isn't possible to require actual psiucjpaacs ID pay, cost responsibility should be

04-02-93 09:46AM P002 MB APR-2-93 FRI 9:45 NM GAS PLUM STREET FAX NO. 315 460 3006 P. 03 '« WSI •»•<» 8 9*4 322 t36? ffUU BUS CCMTE* «3

Robert 1. Pasyto, Su Vice ftwldera Abntnet of Remote Page iMlk Power Ouip«Tatlon DOEUNAKUC Ctonftmw*.'WWra

limited to she etas* that beBaiMe. Ctetapetftion take* away the aJrfUtj? to do aws subsidies without greeting sews, unintended distortions. TUBS, fcft be efficient In program admlnujtntlon to avoid dte eaennous paperwork burdens oa regulators and LDCs that electric DSM programs have ^required. Left moke our plans woddog documents. Tblt lsao!ttiincihronBd1iacasIoMU3iyda|.

R-97&; 04-02-93 09:46AM DOE/NARUC National Coufereace on Natural Gu UK STATE REGULATION AND MARKET DYNAMICS IN THE POST £WENERGY POUCV ACT ERA New Orleans April 27,1993

INDUSTRIAL MARKETS: WHAT YOUR CUSTOMERS REALLY THINK OF THE GAS INDUSTRY

Outline of Remarks of MINTURN G. SMITH Manager, Energy Affairs PROCTER & GAMBLE PAPER PRODUCTS COMPANY

I. Introduction

A. A riddle: How is the gas industry — focused so strongly on capturing poten- tial new electric power generation and gas vehicle markets — like a kid who warts a SuperNintendo set for Christmas?

1. Each wants to score big with the new toy?

2. Even if it were to get the new toy, neither understands fully how to make it work?

3. Each neglects its existing toys/markets and allows them to fall into disrepair? (Even old, reliable teddy bears can get grumpy.)

4. All of the above?

B. In most businesses, it is a basic requirement that sellers of goods and services talk witii their customers.

1. The gas industry professes to have finally come to the conclusion that it is not exempt from this requirement See National Petroleum Council Study, The Potential for Natural Gas in the United States.

2. Unfortunately, many in the industry seem to think that this applies only to potential new customers - not to the birds in the hand.

3. This program properly recognizes that traditional residential, commercial, and industrial markets - not just "new markets" and vehicles markets — warrant attention.

C. As a public service - and as the last obstacle between you and Bourbon Street - I appear to tell you candidly what industrial markets (a/k/a "customers") think of the gas industry. G. Salth UOE/NARUC Conference April 27,1993

D. These thoughts build on discussions held by a focus group of senior fuel procurement executives (no lawyers) from 10 industrial companies as part of the National Petroleum Council's comprehensive natural gas study."

IL The Future Role of Natural Gas

A. Gas clearly has a potentially greater role to play; its relative price, availability, domestic source, and relative environmental impact all suggest increased consumption.

B. But - despite understandable cheerleading efforts by those in the gas industry itself - government regulators should resist calls to give gas (or any fuel) a competitive edge vis-a-vis other options. The aim of government policy should be to remove artificial regulatory and other obstacles to greater, more effi- cient gas UK -mat to promote gas at the expense of other choices.

HI. What Will Keep Us From Increasing Our Gas Consumption?

A. Concerns about reliability

1. Not the gas resource base - we believe that the gas is there and will be developed for the right price.

a. A Gas Reliability Council is nice P Jt, but you really could save the effort

b. Although it is true that you still haven't gotten some of us to shake our nasty memories of the curtailments of the 1970s.

2. Our real concern is about deliverability - U., getting gas from the field, through the pipeline, through the LDC, and to our plants.

a. Concerns about deliverability have stemmed from our broad Inability to acquire reasonably priced firm pipeline capacity (including storage) in our own names.

U Acknowtolfeamt baud* of ttievaluaNe and pmxptive work 4OM especially the tibcra of the Regulatory and Policy Task Force and their consultant, Potter Bennett of BENTEK Energy Research.

-2- Mlatum G. Satita DOE/NARUC CoafMPHK* April 27,19»3

b. The game-playing that has occurred with marketing affiliates in particular and with interruptible service in general has also dampened our confidence in the reliability of the gas option.

c These concerns are now compounded under Order G< as we face a staggering array of potential penalties, capacity release programs which disfavor those who are not in the gas industry itself, and other unpleasant surprises.

d. Interruptibte service is unreliable and will become even less reliable under Order 636.

e. Alternative fuels are often used to hedge the risks associated with using gas, but they carry their own operational cost penal- ties.

3. The gas industry Itself has traditionally sent us mixed messages about the mid- and long-term availability of supply and capacity.

4. Pipeline and LDC operating terms and conditions seem perversely designed to make it as difficult and as expensive as possible for consumers to buy their own gas and arrange for its transportation from wellhead to burner-tip.

5. Prorationing efforts in some states appear to be price-motivated - adding to concerns about reliability and price.

B. Concerns about regulatory uncertainty (and often outright hostility)

1. LDC rate designs continue to include socially-motivated cross- subsidies which ignore industry's need to be able to compete domestically and internationally.

2. Demand side management programs substitute regulators' and LDCs* business judgments for our own with respect to what energy invest- ments are economically justified.

3. So-called "incentive rate" proposals appear to offer only vague and unqaantifiable future benefits to consumers while offering definite, immediate, and certain benefits for LDCs: they should be viewed with cautious skepticism.

-3- Minium G. Smith DOE7NARUC Conference April 27,1993

4. LDCs are so focused on meeting the concerns of their regulators that they often ignore the needs of their customers. At the same time, many commission staffs (often drawn from the ranks of utilities) seem reluctant to take non-traditional steps to reduce the scope of commission authority and oversight; few commissioners or their staffs have experience working among industrial gas consumers and, thus, do not understand our needs.

C Concerns about the utter hick of customer sensitivity and marketing in virtually all sectors of the gas industry

1. With the general exception of marketers, most gas industry partici- pants appear to take their industrial markers for granted, often excluding them from important planning and decisionmaking affecting their interests.

a. Thi* has led directly to higher levels of regulatory activity by industrial gas consumers.

b. Where possible, it will lead to same giving up on gas as not worth the trouble.

2. In general, LDCs are particularly unresponsive to customers' needs. Yet, they should be the ones best able to fill the service gaps left by restructured interstate pipelines.

a. Proposals for LDC "bypass" (alternate sourcing) and cogenera* tion projects are often the only way to get an LDCs attention.

b. LDCs still seem not to have learned that they car* add real value to the Btus they deliver.

IV. Read and Pay Attention To Your Own National Petroleum Council Study on Increasing the Potential for Natural Gas

A. Despise the focus of press attention on a single point - that there is a domestic gas resource base of 1,295 Tcf — there is mmtk that is more important In the Study.

B. For example, far more important are the fallowing dozen conclusions articulated in the Study (emphasis supplied):

4- Mtaum G. SaMi DOE/NARUC CMftraee April 27,1993

1. "The industrial market represents one of the largest potential market areas for growth, or loss, for the gas industry. This sector ha* gone through a major restructuring during the last decade, as a world market has emerged where quality and productivity have assumed important positions along with the continuing need to control costs aod improve operational efficiency. Gas industry success will depend [in part} on ~ an aggressive marketing stance that identifies and satisfies customer needs —

" — [Hie industrial] sector is ~ the largest gas-consuming sector. The natural gas industry will need to be especially cognizant of the changing naturt of the industrial sector and be prepared to respond to these needs in order to retain a dominant market share of this important market." (NPC Study, Executive Summary at 14).

2. "Regulation should refrain from unnecessarily restricting the number and quality of choices made available to the buyers and sellers of energy services; neither should it interfere with the consequences of those choices." (Id. at 19-20).

3. "State commissioners should evaluate and direct as appropriate the unbundling of IDC and intrastate pipeline services to further competition and consumer objectives." (Id. at 20).

4. "The consuming sectors must be able to make decisions based on eco- nomics, service, and environmental requirements with full confidence in the reliability of natural gas being available when, where, and under the terms specified by the contracting parties." (Id. at 22).

5. "Most importantly, the natural gas industry must improve responsive- ness to customers. ~ Each company must listen to its customers to determine energy and service needs, alternatives, and business drivers. The services that add value to natural gas will have to fit customer needs better than alternatives. Success will depend on how the industry develops and markets these services." (NPC Study, Regulatory and Policy Issues (VoL V), at 3).

6. "Where market forces produce choices of adequate quantity and quality, regulatory policies should rely on those market forces. Where market forces exist, but are not adequately developed to provide suffi- cient choices to consumers, regulatory policies should strengthen those market forces. Where market forces cannot produce adequate choices, regulatory policies should continue to protect consumers from exercise

-5- Mlntnra G. Saltk DOE/NARUC Confmacc April 27,1993

of market power by imposing a minimum level of choice on the indus- try, Le^ via the traditional 'regulatory bargain.'" (Id. at 6).

7. "A robustly competitive gas industry will, first and foremost, maximise consumer satisfaction* Implicit in the vision is an industry that will mnga H» and accommodate differing levels of risk tolerance among •ts of the gas industry and its consumers. Risks and associated costs will then be managed by the most capable parly."

"Under this competitive vision, regulators need to step back and allow customers to decide freely their own levels of service and risk tole- rance. Hose customers will then bear the costs cr reap the savings associated with their choices. Because the functioning of individual choice is integral to achieving the public interest, regulators should not osurp or forestall customer choices by substituting their opinion of risk tolerance for that of the customer." (Id.)

S. "Cross-subsidies among customer dosses should be phased out." (Id. at 7).

9. "Access to multiple supply options for all customers should be encouraged. . . . Regulatory policy should provide LDCs with the appropriate cost allocation, rate design, and pricing flexibility to enable LDCs to compete in the marketplace so that regulators do not hav? to promote or prohibit bypass of local distributors." (Id. at 9).

It. "Regulatory actions must be prompt and definitive so that buyers and sellers of the natural gas commodity, of transportation services, and of other gas»related services can make informed economic decisions. Industry decision makers must be able to know, at the time they make their decisions, the actual prices, terms, and conditions that will apply to their transactions. Hie regulatory system should avoid creating mnmeeanry uncertainty in the environment in which business decisions an mask or implemented.' (Id. at 13).

11. "While ease and reliability of transactions have not traditionally been Mfltfy valued attributes in the gas industry, they must become a hall- B£Hrk of a successfully competitive gas industry. Wherever possible, customers should have a choice of sales, transportation, and other services from competing suppliers at various price levels. Regulatory and market support for such vitality in choice should be encouraged through ratemaldng policies, terms and conditions of operation, and billing practices that promote choice and flexibility, promote reasonable

-«• Mutton G. San* DOE/NARUC Conference April 27,1993

business predictability, and, whenever possible, encourage reliance on private, rather titan governmental, action to avoid hardship." (Id. at 14).

12. "Regulators should refrain from pursuing social policies (eg., income redistribution policies) through the regulation of natural gas sales, transportation, or distribution rates. Such an approach does a serious disservice to both - creating bad energy policy and bad social policy. Direct and measurable, but separate, efforts in each respective area will be better designed to further their respective public policy goals." (£.'. at 17).

All of these important observations (and many others in the Study) may be summed up in a single sentence: "Mechanisms must be devised to make it easy for customers to buy natural gas." (NPC Study, Executive Summary at 22). All the rest is simply commentary.

D. ""Tr srnr attpriftr irftfr But the truly critical questions are:

1. Is the gas industry itself really serious about actively pursuing these customer-oriented goals? Or will it simply continue to assume (often incorrectly) that it knows what its customers think and what they want?*'

2. Are federal and state g*s regulators really willing to heed their own (and others') good advice in the NPC Study and rethink the shape of their role in the gas market of the '90s?

* Those who really care about what the industrial gas market — and several other sectors - think of the gai Industry will invest an afternoon reading not just the Executive Summary of the NPC Study, but also the Regulatory and Policy Issues volume (No. V), which includes the overall focus group report, 'Understanding Barriers To and Opportunities for Increasing Natural Gas Consumption."

-7- Natural Gas in Electric Generation

DOE / NARUC Conference New Orleans April 28,1993

Rich Kinder Benefits of Natural Gas Usage

O Environmental: Reduces Sulfer Dioxide (SO2), Nitrogen Oxide (NOX) and Carbon Dioxide (CO2) Emissions

O Economic: Produces Power Cheaper and More Reliably Than Any Alternative Fuel

Environmental Protection and Low Costs Not Mutually Exclusive With Natural Gas as the Fuel Alternative Environmental Advantage Natural Gas Plant vs. a Comparable Coal Plant (500 MW) Nitrogen Oxide Carbon Dioxide (NOX) Emissions (CO2) Emissions 2.94 6 3.0

2.5

Oi "D CO S2 4 2.0 OQ. £ » ~ I n Mil l 1.5 Ton s Pe r

1.0

0.5

0.0 Gas Combined Coal Coat Gas Combined Cycle Source: EPA & AGA Cycle Environmental Advantage Natural Gas Plant vs. a Comparable Coal Plant Sulpher Dioxide Sludge (SO2) Emissions Emissions

350 8 OCA

7 300 - 6 -a « 250 - c a) re >• in t_ 5 3 Q) 200 - 5°g c o 4 g — I- c o 150 - 3 100 - 2 - 1 50 0 0 0 o Gas Combined Coal Gas Combined Coal Cycle Source: EPA & AGA Cycle Environmental Advantage Natural Gas Plant vs. a Comparable Coal Plant

Ash Emissions 150

125 120

I- 90 - 3 0) OQ. c o 60 - V

30 -

n 0 Gas Combined Coal Source: EPA & AGA Cycle Economic Advantage Comparison of Gas Combined Cycle Construction Costs and Plant Utilization Rates

$ kW Capacity Installed Utilization

Gas Combined Cycle $ 683 90 - 95%

Coal-Fired Plant $ 1,820 70 - 80%

Nuclear Plant $ 1,980 60-85%

Source: ICF Resources Economic Advantage Natural Gas Power Plants vs. Scrubbed Coal and Nuclear In Levelized 0 / kwh

Capital Fuel Cost Cost<1> O&M Total

Natural Gas Combined Cycle 1.850 3.650 0.800 6.30

Coal Plant (With 0.20 SO2 Allowance) 4.950 2.330 2.410 9.70

Nuclear Plant 5.400 1.400 2.300 9.10

(1) Assumes Gas Price at Enron Long-Term Contract Price. Assumption: Baseload Operation (65%) Source: ICF Resources Barriers To increased Natural Gas Use In Electric Generation Pricing and Contract Issues

O Difficult to Obtain Long-Term Contracts.., - PUCs Could Disallow if Spot Price Drops - Producers Seek Large Premium

O ...But Reliance on Spot Also Problematic - Gas Prices Less Predictable Than Coal - PUCs Could Find Imprudence if Price Spikes Barriers To Increased Natural Gas Use In Electric Generation Reliability Issues

O Curtailments - Lack of Trust - Insufficient Coordination Between Gas and Electric Industries o O Adequacy of Pipeline Capacity (Insufficient Redundancy)

O Day-to-Day Operational Concerns - No Formalized Gas Operations Manuals - "Sucking Pipeline Dry" with Quick-Startup Cogen Equipment How We Are Responding

O Pricing and Contract Issues - Market Portfolio Approach to Gas Buying - Become Customer Oriented - Encourage Involvement of State Regulators Early in Utility Planning Process

O Reliability Issues - Provide Gas Operations Data to Utility Operators - Encourage Use of Firm Service Through Capacity Release - Let Contracts Determine Reliability-Not FERC - Fashion Workable Construction Rulemaking Explaining The New Gas Industry

Historic Evolving

Service Obligation Contract Terms en o Penalties — Incentives Curtailment - Redundancy Hidden Operating Rules Open Exchange of Data "One Size Fits All" "How Can We Meet Your Needs?" Conclusions o Electric Utilities Have Some Legitimate Concerns... - Price Volatility - Operational Unknowns

© ...But Seem Eager to Rebuild Trust - Portfolio Supply Contracts - Eager to Learn About Gas Operations

O Pipelines Working to Listen to Potential Customers and Squarely Address Concerns

O Cooperation of Producers, Distributors, and Marketers is Critical Teesside Project

1875 Megawatts of Electricity

Uses 300 MMcf per Day of Natural Gas

CT5 Supplies the U.K. with Approximately 4% of Total Power Needs

Teesside Alone Allows the U.K. to Meet Approximately 40% of its Required NOX and SO2 Reductions REMARKS TO THE DOE/NARUC CONFERENCE ON NATURAL GAS IN THE POST-ORDER 636/EPACT ENVIRONMENT

Jacek Makowski Chairman & CEO J. Makowski Associates, Inc. Boston, Massachusetts

New Orleans, LA April 28, 1993 Good morning, and greetings, and thanks to the Department of

Energy and to the NARUC for this opportunity to be with you. On behalf of myself and my company I would especially like to thank the

Electric Generation Association and our friend Ken Malloy of the DOE both for this invitation and for Ken's interest, his energy and leadership regarding the •Imely topic of this conference. The dust is beginning to settle in the wake of Order 636 and the Energy Policy

Act. As a nation, we face important decisions as we look for the path to renewed economic growth, and (a) our energy policies plus (b) their implementation will both play a critical role.

I shall address my remarks directly to the PUC regulators in the audience on the subject of energy policy implementation. Let rns begin by expressing my company's sincere thanks for your efforts.

We view you as the guardians of the competitive process. IPPs thrive on competition. Our efforts to bring forth efficient and low-cost resources would be unavailing without your efforts to crack open a restrictive and monopolistic market environment. We rely on your wisdom, your fairness, and your consistency in decisionmaking.

While I will not be uncritical of your role in today's shifting environment, at the same time I respect the vital importance of economic regulation. Independent power producers and regulators share many perspectives, have frequently made common cause, and are in many respects natural allies in our desire to bring competitive discipline to the energy industry.

The topic of the day is ostensibly natural gas and I take it as my role to speak for the non-utility generators concerning this fuel. I am, of course, delighted to support this effort to explore ways to remove barriers to the efficient use of gas. Let me make two summary observations and move on. First, natural gas is clearly the fuel of choice among a majority of non-utility generators. Second, virtually every projection I have seen shows that power generation is the single largest potential new market for natural gas in North America. Today, suppliers are organizing themselves to serve this market. Beyond that, I would merely note that this audience consists of friends of natural gas. My own company has pursued natural gas projects for over twenty years, through some very dark days for the industry. So, in this brief time I will dwell not at all on the virtues of natural gas. I am just as glad for the chance to give a talk in which i don't have to sell the product. Suffice it to say that the stars are aligning for natural gas. Given a truly free choice, end users of all types, especially power generators, will choose natural gas freely for reasons of cost, convenience, cleanliness and security of supply.

Please let me shift gears to address a more central issue: the role of competition. I will speak as an entrepreneur, a spokesman for the smaller fish in this rather murky pond. Because we employ interstate and local gas services and sell through the electric utility industry, gas-fired IPPs are vitally affected by the simultaneous and analogous restructuring of all three of these industries.

'' L'l After the oil shocks and other disasters of the 1970s, this nation has made a commitment to give play to competition in the energy industry. If this federal commitment is to bear fruit, it requires consistent application of this policy at all levels, federal and state. So

I ask you to ask yourselves: do you believe in the essential virtue of competition? Do you doubt that, where workable competition can exist, it is the surest pathway to national and consumer benefit?

Today, the principles of choice and competition are embraced throughout the world. In our immediate realm they have been expressed in recent years in the Wellhead Decontrol Act, the PLJHCA reform provisions of the Energy Policy Act, and in Order 636. But competition is much, much more than a current trend in energy regulation in the United States. It is the historic organizing principle of our economic life. It is a pillar of our political culture. Its underlying theory is sound and well-supported: the calculus of the marketplace, featuring many willing buyers and sellers, reflects much better all of the values and preferences and productive capabilities of a society than the dictates of the powerful few ever can. Competition has beer, and must be embraced for reasons beyond its mere theoretical appeal. It is a matter of pragmatic necessity as we face overwhelming global competitive pressure.

Practically speaking, competition spurs innovation and cost reduction.

As other nations around the world adopt and benefit from the philosophy that made this nation not only great and free but the mightiest economy in world history, we have no choice but to continue forward on this path.

Market-based competition in the gas and electric industries has made tremendous strides in recent years. It has won the intellectual battle. Yet it faces obstacles in the years immediately ahead, key among them the rate of implementing this policy. Now is the time to have the courage of our convictions and ensure that the philosophy of competition succeeds in the marketplace. A competitive market has different requirements from the traditional regulated environment.

Just ao the electric and gas utilities' role is being restructured, so too must you reexamine your own role. For no longer can you make decisions in proxy for competitive forces; instead, I believe, you must become facilitators and implementors of the competitive process itself. Please let me take a few moments to describe what makes the competitive power industry distinctive, and the constraints we face.

Our industry is exceptionally diverse. We employ a variety of development strategies, generation technologies and fuel sources.

We are constantly seeking ways to increase efficiency, reduce emissions and find other ways to gain the edge.

What we all share in common is that we do business not by regulator/ compact but by private contract. The contract spells out rights and obligations and provides us with the certainty we need to make substanti il long-term commitments, not just to build a generating machine but to make a functional project. I point to a project such as the Ocean State Power project in which my company was the lead developer. For every dollar spent on a large 500-MW power plant, two dollars were committed to underpin a twenty-year commitment to pipeline capacity and natural gas reserves. The contract-based approach eliminates the cost-plus rate base mentality which was so tolerant of poor judgment, and which contributed to catastrophic overruns in the 1970s and 1980s. We make the commitment not to come back to you because we overspent on construction or underestimated on operating costs. But because there is no regulatory safety net for private, non-utility capital, large commitments cannot be made in an environment of confusion and regulatory instability.

Because my company has a I J>ng consulting heritage in the natural gas business, we have a metaphor we use for the project development process. We speak of "flanging up" a project.

Figuratively speaking, we bolt and weld together the key project contracts to ensure that there is a rigor and integrity to how the long- term contracts mesh and how risks are allocated. The whole structure must then be "flanged up" to a financing source and survive a rigorous process of review. For it is we and our financiers who, in place of the ratepayer, and in reliance upon contracts, place long-term dollars at risk. The willingness of lenders to back project-financed deals with high initial debt ratios gives powerful testimony to the

soundness of this approach. The project financing process provides

an effective screen against projects that lack overall integrity.

I am proud of the success of this approach to developing new capacity. Quite naturally, we believe it is r.,ore likely to lead to low- cost results than the traditional approach, which gave rise to the disastrous rate base mentality. Today, robust competition exists in the wholesale electric generation market, and IPPs have emerged as strong and sophisticated players. I believe you look to us to continue to play an important role

Yet despite the success of competition in recent years, we find ourselves at a crossroads. We face trends on the legislative and regulatory fronts that threaten to undo the progress that has been achieved by subordinating competition to other goals. You may not view the current situation as a crisis, in the sense that the lights are not flickering. But, in the literal sense of the word, we are indeed at a moment of decision - of multiple decisions, in fact.

8 Now there is nothing new about conflicting government policies

affecting the energy sector. In the past, however, when monopolies

ruled the roost, they more or less muddled through, accommodating

the increased costs and inefficiencies that resulted from such policy conflicts by raising rates. What is new is that our energy policies are now overtly market-based but there is still a strong residue of command-and-control regulation. Many policy initiatives, including some being pursued by your own agencies, are predicated on an obsolete view of the marketplace, what I would term a sort of default mindset in the public and among some in government that the utility industry remains unalterably monopolistic in nature. Having this view, a poiicymaker can falsely persuade himself that his actions only affect one corporate entity, the utility. This being the assumed case, then the policymaker may be tempted to consider only the reasonableness of the overall result, while ignoring the competitive distortions and perverse incentives that are caused along the way by his initiatives.

But the regulator's decisions now implicate large numbers of third parties in the marketplace. Let me offer a handful of illustrations of how our regulatory frameworks at the state level have not yet caught up with today's competitive realities.

o . First of ail, consider the skewed incentive utilities face to build

plants, or even to pursue incentivized demand-side management

programs, rather than buy cost-effective power. It has bean

conclusively shown that the generation marketplace is extremely

competitive. If there ever was, then there is no longer any natural

monopoly in generation. Yet utilities by and targe earn returns for

their shareholders through building or DSM but do not when they buy

third-party power. As a result, many utilities today, given

strengthening balance sheets and free cash, are powerfully attracted

by the spectre of high regulated returns on such investments, even if they are not least-cost for ratepayers. This flaw in regulation makes it entirely rational for utilities to act in a perverse way. As a result, we find utilities issuing RFPs only under duress, and even seeking to circumvent or shut down competitive processes.

I urge you to realign the incentives you signal so that utilities will prefer truly least-cost resources. The NARUC's 1988 resolution speaks to this point: a utility's least-cost plan should be its most profitable plan. You might consider whether there is any rationale for

10 continuing to offer rate-base treatment for generating assets. Unless

you want to bribe utilities to do the right thing, then please start

thinking seriously whether generation should be unbundled altogether

and spun out of the core utility function. It is commonly believed we

will reach this point in twenty years. If we ptan an equitable

transition, we could reap the benefits of such a market structure a

great deal sooner.

In a second area, let me note, with respect, that the increased regulatory activism of the past few years has not all been motivated by a desiro to increase competition. Some commissions invoke their broad statutory powers to pursue ambitious social agendas that go beyond remedying distortions that arise from utilities' market power. I would put the movement to impute externalities in this category.

Other policies go beyond a simple endorsement of resource diversity and expressly favor certain fuels or technologies. Some commissions, in all candor, apply grossly relaxed cost-effectiveness standards to conservation programs or renewable-based energy.

11 If the utility were the single corporate entity affected by the

regulator's preferences, such activities would be less objectionable.

When such policies reflect the will of an elected legislature, we

willingly accept them. However, I see a fundamental problem when

regulators' personal preferences can result in major winners and losers in the marketplace of ideas and technology.

As a third area of concern, our industry strongly supports the market-based theory underlying the Clean Air Act Amendments of

1990. At the same time it is not yet clear that a truly free market for emission rights will exist. We remain concerned that utilities will use their dominant position to deny to the IPP industry necessary access to emissions credits and allowances for future development. Utilities may be reluctant to part with allowances because of the spectre of

PUC review of such strategic decisions. The goal of competition will be fundamentally threatened if utilities are encouraged to hoard these scarce resources. Our industry believes that access to credits and allowances should be fair and non-discriminatory, so that control of emissions rights does not equate to control of the results of the

12 resource selection process. Ratepayers should know that these

valuable rights will be allocated to the most cost-effective projects that

can put them to best use. It may be appropriate to structure a

shareholder incentive for utilities to make available the credits and

allowances they hold to the winners of competitive solicitations for new capacity in the future.

The next two matters are subject to decisions in the near future, by yourselves and by the Congress. As you know, Section 712 of the

Energy Policy Act obligates each state to review a number of issues associated with Exempt Wholesale Generators' financing and fuel arrangements by no later than October of this year. We are naturally concerned by the prospect of unnecessary new regulatory requirements on the competitive power industry. Without laying out our industry's views in detail on the questions to be addressed, let me simply observe that the project financing process, as I earlier alluded, already entails a rigorous review that offers you a strong assurance of the integrity of IPP projects in advance of construction. I believe that our industry's approach to financing and reviewing fuel plans

13 provides more than adequate protection for ratepayers. It is certainly

preferable to the conduct of lengthy, expensive and litigious

retrospective prudence reviews of utility construction programs, undertaken only after the dollars have been spent. Our industry's strong view is that any additional requirements would only increase the cost of projects without providing an incremental public benefit.

Fifth and finally, although this is not a matter for your decision, I urge you to consider the competitive implications of the proposed Btu tax, and to reconsider NARUC's announced position. While the PUCs are caught in a dual role, as protectors of consumer interests and of the competitive process, it is worth noting that the President's express intent is that ultimate consumers, and not producers or middlemen, should bear this tax. Only when end users see and feel the price signal of the tax will it achieve its goal of influencing consumption.

There is a desire to impose this tax upstream of the retail level.

It is essential to recognize that due to the variety of private contracts in today's energy market, any such shift in the incidence of the tax will

14 give rise to a random pattern of winners and losers. Different forms of treatment would give rise to invidious distinctions between utilities and IPPs. Some proposed formulas would lead to perennial windfall payments to foreign energy suppliers. The IPP industry has attempted to be supportive of an energy tax from the beginning. My company's strongly-held view, however, is that any tax that is not imposed at the retail level, or through the fuel charge and gas cost adjustment mechanisms, would threaten to undo the good that competition has achieved in recent years.

In conclusion, the process of market reform is well advanced.

The role of the utility is being fundamentally redefined and this is being accepted by forward thinking executives and grasped by them as an opportunity for their companies. This cat cannot be walked back. The time has come for the regulatory community to face these new conditions squarely, and to refocus on its core mission - to prevent the abusive exercise of market power. Competition must never, never bo seen as merely the handmaiden of regulation. It is not simply one "tool" in the regulator's "tool kit." To the contrary,

15 under our economic system, regulation must be employed as a matter

of limited exception. The value of your efforts is great when targeted

to the proper objective; but it falls off when those efforts ignore

today's market context and impede opportunities for workable

competition, If you use your powers to determine market outcomes, you will fail. I urge you to see yourselves instead as facilitators of the competitive process.

The fork in this road at which we find ourselves presents us, essentially, with two choices. We can follow one fork to an orderly free market in which the kind of activity I have referred to can take place, with prices determined by open competition. Down this road, your powers may be used to facilitate and to accelerate orderly competition. The other fork, I fear, leads to the balkanization of regulation: free market forces contending with a rear guard action by the utility nomenklatura, slipping up and slowing dsvvn the inevitable advent of the new regulatory regimen. Down that path lies the risk of civil war. The long journey to this point has been both satisfying and arduous. But the journey is not over. And you cannot stop half way.

16 April 26, 1993

Thank you very much for your invitation to speak to

. I think it appropriate that a

representative of Entergy Corporation be a participant in a natural

gas meeting of this sort because Entergy has been and even today

continues to be one of the largest electric utility users of natural gas in the country. In fact, prior to 1974, we were practically

100% natural gas-fired generation. In 1974, our first nuclear unit came on line and since that time we have added 3 other nuclear units and 4 coal units prompted largely by the Fuel Use Act of

1978 and natural gas curtailments. Needless to say, that with the availability and price of fuel as they are currently today and projected to be in the reasonable future considerable capital savings could have been achieved had we known the law and the supply situation would change as rapidly as it did. Entergy

Corporation's use of natural gas peaked in 1972 at 331 BCF and last year, even though 65% of our capacity is fired by natural gas, our use of gas was only 194 BCF. Our experience is not unlike the

industry as a whole. It peaked in 1972 as well at 4.2 TCF (18% of

all gas consumed) and represented 22% of total electric generation.

1990 use was down to 2.8 TCF (16% of total gas consumed) and represented 10% of total generation. I well remember my early days as a utility executive worrying about the delivery of fuel oil to our plants that were designed to burn natural gas and, in many cases, worrying about our ability to keep an adequate supply of fuel oil moving for our very large amount of gas-fired generation, for which no natural gas fuel was available at the time. All of these things together prompted us to begin our switch from natural gas to coal and nuclear fuel. Our experience is not unique in this part of the country. For example, even as recently as 1990, 84% of all U.S. electric utility generation by natural gas was in a local six- state area so natural gas obviously has been and to some extent continues to be a fuel of choice in our region of the country.

Seven local states, that is, Texas, Louisiana, Oklahoma, Arkansas,

Kansas, New Mexico, and Wyoming today produce 90% of our domestic natural gas and use 36% of the total consumption. Most

everyone, including us, project a large increase in the use of natural gas as a fuel for electric generation. However, going back to my last set of numbers, a large increase is required just to reach the 1972 levels (an increase of about 50% in natural gas usage by the country is required just to get back to the 1972 levels.)

The potential problem I see is that previously the large users, such as Entergy, were in a relatively small geographic area of ;he country which produced large amounts of natural gas. Many of the new projects being projected today are much more geographically dispersed and suddenly it may not be reserves or availability that are of concern, but the deliverability. The utilities in the natural gas areas are summer peaking companies, which helps the natural gas industry to supply the need. Many, if not most, of the new usage is scheduled to be in nonproducing areas and are winter peaking for electricity adding to the potential supply problems.

Let's take a further look at the situation.

6.': I Eighty-nine percent of the natural gas used for electric generation today is in steam turbine equipment. Most all new projections are for combustion turbines or combined cycles, totally different technologies which will require totally different gas delivery capabilities as compared to the old strain turbines.

Certainly our assessment of the market today is that the needs appear to be peaking units, many of which would be used at 10% or less capacity factors. The question is, do we have, or can we afford to build, a delivery system to allow several thousand megawatts of peaking capability which could all be started at approximately the same time because the need would develop at approximately the same time in a geographic area, be on for a few hours, then all turn off at approximately the same time again. I think we are in for a whole new set of problems.

Such a large amount of capacity coming on in a delivery system not accustomed to delivering that amount of capability could literally suck uie pipe dry, stay on a short while until gas is on its way, and then shut down and potentially create a need to

vent the onrushing gas supply.

Let's examine for a moment some of the differences between

steam turbines using natural gas as a fuel, the preponderance of which have been in gas producing areas, with the operation of combustion turbines for p

(1) Steam turbines take time to start up and then to ramp up, so advance warnings of gas consumption are available.

Combustion turbine units come on line and go to full load in a matter of minutes.

(2) Steam turbines in our part of the country are designed to be base or at least intermediate units. Most combustion turbines are designed to be peaking units and may have extremely low capacity factors.

(3) Electric steam turbine natural gas delivery pressure is a nominal 50 psi or the normal pipeline pressure of 100 psi. Much higher pipeline pressures are required for combustion turbines-

200 to 600 psi.

(4) AJso with the combustion turbines, more expensive distillate fuel oil is the only alternative fuel source, where the old steam turbines could use much less expensive fuel oil.

(5) Steam turbines tend to be committed on an individual unit by unit commitment schedule planned sometime in advance.

Combustion turbines will be committed for relatively short time frames in groups as need for peaking or emergency capacity may develop quite rapidly.

To fully appreciate problems to which solutions must be found as we greatly increase our natural gas fired generation across the nation, I think it is also necessary to examine, at least the past if not the current, industry differences and philosophies between the electric industry and the natural gas industry.

Electricity is a much different form of energy than natural gas.

(1) Electricity moves at the speed of light. Natural gas is a much slower moving commodity, perhaps 25-30 per hour. (2) Secondly, electricity has very little storage capability,

where with natural gas some storage is integral to the system and additional storage has been or is being developed.

(3) With electric generation, plants have reasonably short ramp up time whereby the normal incremental demand on natural gas infrastructures may need 24 hours notice for nomination.

Perhaps equally important, although changing, is the phiiosophy of handling contingencies. The electric utility method of handling contingencies has been redundancy and alternative supply mechanisms where the natural gas response to contingencies has been curtailment - two totally incompatible philosophies. I would be the first to say that the natural gas industry has recognized this and is taking steps to correct it, but I am not sure that these steps can be taken as rapidly as required if some of our natural gas electric generation projections prove to be true.

0-> So, let's take a quick look at what must oe done. There is no doubt that natural gas is the current fuel of choice and there are very obvious reasons.

(1) It is a premium fuel.

(2) It is environmentally more acceptable than some.

(3) The technology for its use is relatively simple.

(4) Normally the capital expenditure for installation is less.

(5) Siting is easier.

(6) Environmental compliance is easier.

(7) Construction schedule can be accomplished in a short period of time.

(8) I might even add it is probably the political fuel of choice with all of these advantages. It is no surprise that our projections show tremendously increasing use of this fuel.

Current NERC forecast has increased gas-fired generation projections from 15 gigowatts in 1988 to 39 gigowatts in 1991 projections. That trend toward increased projections of natural gas usage continues and will probably rise considerably more over the next two years. So, if we have the fuel available, as most experts agree we do, and if it is the fuel of choice, then certain operational problems must be solved. But my point is, they must be solved, and to solve them will take a greatly increased natural gas storage and movement capability that is not in our current natural gas infrastructure. Providing this large amount of flexibility, deliverability, and quick on and quick off capability will not be cheap.

6 r\ >•< NATURAL GAS, POWER GENERATION AND ORDER NO. 636: REGULATORY AND COMMERCIAL ISSUE8 THAT MUST BE ADDRESSED FOR THE COURTSHIP TO LEAD TO CONSUMMATION

James F. Sova, Jr. Partner Hunton fi Williams Washington, D.C. 20006

ABSTRACT The ongoing restructuring of the interstate natural gas pipeline industry pursuant to the Federal Energy Regulatory Commission's Order No. 636 presents both opportunities and threats for expanded use of natural gas as a power generation fuel. As the pipeline industry and its regulators write on a clean slate, developing transportation tariff provisions that will guide tlw provision of unbundled transportation services, they can do many things to make the use of gas in power generation applications more attractive, less challenging for plant operators and less financially risky than it has been in the past. Or, the industry could be allowed to adopt transportation tariff provisions that will increase the operational and financial risk of committing to gas as a power generation fuel. Power generators reguire substantial flexibility in their fuel delivery systems in order to accommodate the wide swings in electric demand to which they must be prepared to respond instantaneously. They also require some certainty as to the delivered price they will pay for the fuel they consume. The principles of economic dispatch cannot easily tolerate retroactive changes in the various components that make up the delivered cost of natural gas. Although FERC still has a long way to go in completing the pipeline industry's restructuring, FERC actions to date are not encouraging from the perspective of power generators. FERC has been responsive to a few of the operational concerns advanced by power generators in various restructuring proceedings. For the most part, however, FERC has chosen command-and-control tolerance and penalty regimes over more flexible approaches, and has declined to direct pipelines to afford shippers such as power generator: means of avoiding or mitigating their penalty risk. While FERC has professed to finding merit in many of the power generators arguments favoring flexibility, it has declined to reserve judgmen on pipeline operational tolerance and penalty provisions pendim the development of more information on the potential impact o those provisions. The tariff provisions that have been acceptei thus far are not nearly as friendly to the use of gas for powe: generation as they might be. NATURAL GAS, POWER GENERATION AND ORDER NO. 636: REGULATORY AND COMMERCIAL ISSUES THAT MUST BE ADDRESSED FOR THE COURTSHIP TO LEAD TO CONSUMMATION

INTRODUCTION Natural gas continues to be promoted aggressively as an ideal fuel for electric power generation. These promotional efforts have generally been successful: gas has achieved a high - level of acceptance among non-utility generators (and, importantly, their financiers), and has made significant inroads with many electric utilities, including some whose generating resources historically have included little or no natural gas-fired capacity. Utilities and non-utility developers alike are constructing substantial amounts of new gas-fired capacity in many regions of the United States; utilities in areas traditionally not highly reliant on natural gas as a power generation fuel are undertaking or considering the repowering or supplemental firing of existing coal- and oil-fired facilities with gas. Observers of the natural gas and power generation industries are nearly unanimous in the view that natural gas1 share of the power generation market, which has grown substantially in the past few years, will continue its dramatic increase. It is apparent that many (at least in the natural gas industry) believe that further natural gas penetration of the power generation fuels market is a "slam dunk," given the many environmental, capital cost, efficiency and financing advantages of gas-fired generating c?r>acity over capacity using other fuels. These industry p vticipants generally view the challenges of expanding the natural Qv.s infrastructure and natural gas deliverability to accommodate growth in power generation load as significant, but eminently manageable. Power generation, far and away the gas industry's largest potential growth market,1 is seen as gas1 "manifest destiny." The conventional wisdom could be wrong. The natural gas industry is currently undergoing a fundamental restructuring driven both by regulators and market forces. The result of this restructuring could be a reconstituted natural gas industry adequately equipped (in both the physical facilities sense and in the commercial sense) to meet the special demands of gas-fired power generation loads as it meets its traditional demands. Alternatively, the result could be an industry structured with the objective of minimizing the operational and financial risks faced by the incumbent participants (pipelines, local distribution companies and producers), at the expense of the operating flexibility and pricing stability required if the courtship of power generator loads is to develop into a long-term, healthy relationship. Trends that are discernible in the ongoing restructuring of the interstate natural gas pipeline industry before FERC appear more likely to lead to the latter result than to the former. Recent trends in the price of natural gas and new expressions of concern regarding gas deliverability likewise present (at least to the skeptics within the power generation industry) a picture of an industry ill-suited to the task of increasing power generation use of gas. FERC so far has been willing to accept restructured interstate pipeline tariff provisions that include inflexible operational protocols, tight tolerances and onerous penalty provisions that are intended to govern the transportation services pipelines will render in the newly unbundled world. These provisions will render the use of natural gas for power generation operationally difficult, unnecessarily costly and, in some cases, so risky in terms of potential financial exposure as to render gas uncompetitive. Although some interstate pipelines have proposed operating conditions that are conducive to (or at least not inimical to) the use of gas for power generation purposes, many have used the opportunity presented by the restructuring mandated by Order No. 6362 to strike a balance tilted decisively in favor of their (legitimate) operational concerns as against power generators' needs for flexibility and with the needs of other pipeline shippers. Electric utilities, cogenerators and independent power producers generally view natural gas as an attractive power generation fuel resource, and have formulated their plans for generating resource additions accordingly. Indeed, power generators have already committed substantial capital resources to gas-fired capacity (and related infrastructure). Now, however, power generators are encountering major impediments to the increased use of gas for power generation originating — ironically — from the natural gas industry itself, in the form of inflexible pipeline operational limitations, tight tolerances and substantial penalties proposed by interstate pipelines in the course of their restructuring proceedings. This paper first describes electric generation operations as they are affected by natural gas availability and pipeline operational constraints, employing data drawn from actual gas-fired generating unit experience. It next identifies some of the more troublesome operational restrictions and penalty provisions that have been proposed by interstate pipelines that will have an adverse impact on electric generation operations. I wish to demonstrate that rigid operational requirements and punitive penalty provisions, imposed without regard to actual operating conditions on pipeline systems, will adversely affect the economic dispatch of gas-fired electric generating capacity and will negatively affect the attractiveness of natural gas as a power generation resource. I then suggest principles that should guide the development of operational protocols, tolerances and penalty provisions. These principles are intended to spawn alternative means of addressing pipelines' legitimate needs to ensure the operational integrity of their systems, to maintain relative balance on their systems, and to deter conduct detrimental to the maintenance of adequate service, while at the same time permitting the flexible and integrated operation of pipelines and power generation loads that will be necessary if gas is to continue to be viewed as a viable fuel for power generation purposes.

DISCUSSION The Problem: Gas-Fired Power Generators Require substantial Flexibility in Their Fuel Delivery systems Electric power generators, like interstate natural gas pipelines and local distribution companies, are required either by state law or contract to furnish reliable service. To do so, power generators must have reliable generating resources at their disposal. Where natural gas is used in a generating facility, the reliability of the fuel delivery system supporting that facility is critical to a power generator's achievement of this paramount reliability objective. For this reason, the natural gas transmission system is becoming an increasingly important factor in power generators' reliability calculations. If the natural gas transmission system cannot consistently and economically deliver gas to power generators, then the reliability of gas-fired facilities will inevitably suffer. Natural gas will succeed in increasing its penetration into electric generation markets only to the extent that it can be shown that the gas will indeed be available to power generators on a reliable basis — that is, that natural gas will be available when power generators need it, subject to operational limitations that are consistent with the operational realities faced by the power generation load, at a delivered cost which is both predictable and, when all charges are totalled up, competitive with alternative fuels and with the cost of using alternative generating resources. Gas-Fired Power Generators Must Vary Their Takes Hour-to-Hour. Electricity demand — and, hence, demand for power generation resources — is highly variable over the course of a given 24-hour period. Gas-fired electric generating facilities, in particular, are subject to wide operational fluctuations, because many gas- fired facilities are dispatched on- and off-line to meet peak electric load requirements or to compensate for the loss of other generating resources. As a consequence, the load presented to gas transmission systems by gas-fired power generating facilities swings up and down over the course of a day, often quite dramatically and unpredictably. The graphs which follow illustrate the fluctuations in the fuel requirements of gas-fired generating facilities. Graph No. X shows the gas generation load profile experienced by one electric utility using, for the most part, conventional gas-fired boilers, on its peak day. As that graph demonstrates, the depicted utility can experience a swing in its aggregate gas demand for power generation over the course of a single 24-hour span of greater than 2.5 to 1, i.e., its hourly gas consumption in the hour of maximum gas usage can be more than 2.5 times its gas consumption during the hour of minimum usage during the same 24-hour period. Even on the day of minimum power generator gas usage, the util.^y depicted in Graph Mo. 1 experiences a swing of 2 to 1 in its hourly gas consumption (see Graph Mo. 2). SUB-REGION "A11 GAS GENERATION LOAD PROFILE - PEAK DAY

PLANT NO. 3

s

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 19 17 18 19 20 21 22 23 24 HOUR LOAO PROFILE FROM ACUTAL NET GENERATION - 1991 PEAK DAY HEATRATE = 10,750 BTU/KWH SUB-REGION "A" GAS GENERATION LOAD PROFILE - MINIMUM DAY

PLANT NO. 1 PLANT NO. 2 £0 PLANT NO. 3 1,400

1,200

1,000 4OU.6 J(M C 800

8 CO 600 H «.JSU M § O 400 o 200

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 HOUR

LOAD PROHLE FROM ACUTAL NET GFJ ORATION -1991 MINIMUM DAY HEATRATE = 10,750 BTU/KWH The enormous swings depicted in the preceding graphs are a fact of life for power generators dependent on natural gas. They result not from inadequate discipline on the power generator's part, nor from efforts to "game11 the system by injecting and withdrawing gas in patterns calculated to benefit the user, but rather from the fundamentally variable nature of electric demand over the course of a day and over the span of a month, season and year. If gas is to support additional power generation load, the gas delivery system and gas pipeline tariffs must accommodate these unavoidable hourly swings to the maximum extent feasible. Gas-Fired Power Generator Demands Vary Dramatically from Day to Day. Power generation demands for natural gas vary dramatically from day to day, as wall. Numerous factors affect the dispatch of gas-fired generating resources. Among these are • Supply-side resource availability including, for electric utilities, the availability (and price) of off-system purchased power (including non-utility generated power, much of which is gas-fired); • Price and availability of fuels competing with gas (principally coal and oil) for use in generating units; • Daily, weekly and seasonal weather fluctuations; and • Electric transmission system configurations and loadings (e.g., under certain circumstances transmission system constraints can limit the availability of off-system power and hence can require additional use of in-system resources, including utility, and non-utility generating resources). These factors are, by their nature, not subject to a power generator's control. They can interact in unpredictable ways, requiring virtually instantaneous adjustments in generating output. Gas-fired plants are particularly well-suited to these sorts of adjustments; moreover, the relatively high (at least as compared with coal and nuclear units) variable cost of running gas-fired generating units will typically lead a dispatching utility to take gas units off-line when electric system loads slacken or system constraints ease. The daily variability of gas-fired generation use is particularly pronounced where gas-fired "peaking" units are involved. Such units are dispatched on short notice to meet peak requirements on a given electric system. They may not run for days on end, and then, on as little as 15 minutes' notice, may be brought up to full capacity for a period of as short as a few hours. Graph No. 3 depicts the operations of four such peaking units, located at Virginia Power's Gravel Neck Generating Station outside Richmond, Virginia, during the month of July 1992. The Gravel Neck facility, which consists of four simple-cycle combustion turbines, operates on a highly variable and intermittent basis, depending upon weather conditions and the availability of lower-priced generation resources. This intermittent and variable use leads, in turn, to highly variable consumption of gas, as Graph No. 3 shows.

10 July 1992 Gas Consumption Gravel Neck

o I o o o 8 c o

E n c o O 10 -

5 -

1 I 3 I 5 T 7|9 I 11 I 13 I 15I 17 1 19 1 21 I 231 25 I 27 I 29 131 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Date In July, the Gravel Neck facility consumed over 250,000 Dth, with an average daily consumption of gas on days which the units ran of slightly more than 14,000 Dth. On many days, these units did not run at all. It is not possible to predict precisely when the Gravel Neck units will run; it is therefore impossible to make reliable nominations for transportation service to support these unics 24 to 48 hours in advance of the time when the units will in fact consume gas. Most pipelines are requiring at least this much advance notice; at least one pipeline has proposed a 96-hour advance notice requirement for first-of-the-month nominations.

In such circumstances, differences between receipts and deliveries, as measured both on a nominated and on an actual basis, are inevitable. Indeed, the average daily imbalance at Gravel Neck during the month of July would have been 9,200 Dth, or about 70 percent of the average consumption of gas experienced on days on which the units ran. This hypothetical imbalance would have had little practical impact on the pipelines involved: they were able to serve Gravel Neck when service was required. In any event, as of the close of the month Gravel Neck and other Virginia Power units were able to "zero out" their various imbalances (although on a day-to-day basis they would have had penalty exposure under some pipeline tariffs). Imbalances developed under the circumstances depicted in Graph No. 3 typically reflect usage that is both greater than and less than expected usage during any given day or period, with variances in either direction being the product of variable factors ordinarily beyond the control of the power generator using gas. While greater usage than the levels projected can sometimes be limited by using higher cost cilternative fuels, uncfer-usage on a given day is often the result of unexpected changes in weather and electric demand. There is little a power generator can do about this. Even modern combined-cycle combustion turbine units being operated as intermediate-load and base-load units present significant challenges in terms of maintaining relative balances between receipts and deliveries. Graph No. 4 depicts operations at Virginia Power's Chesterfield Generating Station, also located near Richmond, Virginia. Cl sterfield, which consists of two combined- cycle combustion turbin units, employs the latest in gas turbine technology. Because Ch sterfield's units are highly efficient, they remain in operation ior extended periods at current gas prices (i.e., in July the Chesterfield units were run all day most days). During July Chesterfield consumed almost 2,000,000 Dth, for an average daily consumption of 64,000 Dth. Although the Chesterfield units operate much more consistently than peaking units such as the Gravel Neck units, in July Chesterfield ran an average daily imbalance of 6,300 Dth (about 10 percent of its average daily consumption), with a maximum of over 25,000 Dth (about 40 percent of the average daily Chesterfield gas consumption). The pipelines

12 serving Virginia Power were able to cope with Chesterfield's requirements, and Virginia Power was able to approach a zero imbalance level by month's end.

13 Consumption (000 Dth/Day)

o 2 o |

GRAPH NO. 4

14 Forced outages Are a Pact of Life for Electric Generators of All Types. In addition to the swings in gas demand that result from daily and hourly changes in electric loads, all power generators can and do experience forced outages. Steam pipes can burst, turbines can throw blades, any of the complex electrical and mechanical systems that make up an electric generator can fail unexpectedly. Such failures can require the generating unit to be immediately shut down or otherwise have its load reduced, and they can require that standby generating units be brought on-line to compensate for the loss. This can dramatically alter the gas requirements of the generator. There can be a significant delay before the gas supply being delivered to the pipeline can be changed to match this drop in load or the start-up of a compensatory gas-fired unit can be initiated.

The Requirements of Electric Generators Have Been Accommodated by Pipelines Under Their Pro-Restructuring Tariffs. Pipeline operations and tariffs that pre-date the ongoing restructuring of the natural gas industry have allowed electric generators to use substantial amounts of natural gas without disrupting the reliability of the system. They generally have been able to do so without resorting to onerous penalties that will be triggered by any significant changes in electric loads ir forced outages. Historically, those pipelines serving substantial power generation load have dealt with the challenges of serving such load by communicating with their power generator customers, and the pipeline and customers have succeeded in working together to maximize the electric generators' consumption of natural gas without adversely affecting gas system operations. Power generators consumed over 4.0 Tcf of natural gas in 1990.3 Pipelines generally were able to accommodate this load without resorting to harsh penalties to discipline their customers.4

Recipe for Making the Problem Worse: Pipeline Restructuring Proposals That Lack the Flexibility Required to Accommodate Power Generation Loads Many of the pipeline transportation tariff provisions that have been proposed in restructuring proceedings do not take into account the facts of gas-fired power generator life described above. Because they do not recognize the real needs of gas-fired power generation loads, these provisions could operate in ways that would be hostile to the use of gas for power generation purposes. Inflexible Uniform Hourly Flow Requirements Would Mandate Operations of Which Most Power Generation Loads Are Incapable. Most pipeline tariffs have for some time specified that pipeline customers must arrange their takes of gas "as nearly as possible at uniform hourly rates."5 How "nearly" it is "possible" to approach the ideal of uniform hourly takes varies, of course, from customer to customer. In the case of power generators, as discussed above, anything even approaching a uniform hourly rate of take is often 15 impossible. Tariff provisions legislating this form of operational perfection present real obstacles to increased gas use for many power generators. In their restructuring proposals, several pipelines have given new emphasis to tariff provisions requiring uniform hourly rates of take. Texas Eastern Transmission Corporation, for example, has reserved to itself the right to "require uniform hourly delivery if necessary to protect the integrity of the Pipeline's System, or if necessary to satisfy Pipeline's firm obligations," under pain of a $25/Dth penalty for noncompliance.6 FERC has approved this provision,7 over objections that the pipeline does not have the ability to monitor g«s flows on an hourly basis.8 Similarly, Panhandle's Rate Schedule FT provides for uniform hourly rates of delivery to firm delivery points equipped with flow control equipment.9 FERC appears to have accepted this aspect of Panhandle's restructuring tariff filing.10 While power generators would not argue with the proposition that hourly take flexibility must give way when uniform hourly delivery is truly required to protect pipeline system integrity, the mere possibility that uniform hourly takes will be required on any regular basis will have a chilling effect on the development of additional gas-fired power generation. Even measures touted as being "pro-flexibility" are problematic: that a pipeline has retained the right to permit deviations from its restrictive rate- of-take requirements is not particularly reassuring to power generators. There is always a possibility that a pipeline might not agree to waive a particular restriction; where the pipeline can choose whether or not to permit the necessary deviations employing criteria that cannot readily be understood and applied in advance by shippers, there is no practicable way of predicting what will happen or of policing what has happened.

The consequences of deviating from the uniform hourly take standard can be quite severe, both for power generators and their customers. For example, if Algonquin Gas Transmission Company's "contractual rate-of-flow" tariff provision were violated during a period in which notice of system stress conditions had been posted, the errant shipper would confront a penalty of $15 per MMBtu "[t]o the extent that deliveries to Customer during any period of one hour exceed 104% of l/24th of the scheduled daily quantity...for reasons not attributable to curtailment pursuant to § 24 and without the consent of Algonquin . . . .H11 At this penalty rate, the electric utility whose operations are depicied in Graph No. 1 would have been subject to penalties for failure to maintain a uniform hourly rate of flow on the peak day of approximately $250,000, as compared with an actual gas cost for that day of $825,000 (assuming gas costs of $2.00/dth). That is, if the utility depicted in Graph No. 1 had varied its hourly takes in accordance with demands on the electric system without having obtained the pipeline's consent, the utility would have experienced

16 an increase in its gas costs of more than 30%. it is, moreover, little comfort for a power generation customer to be told that it has the ability to vary its nominations from hour to hour to track its hourly changes in gas usage where (as is true in tne case of Algonquin) the pipeline remains free at any time to post a notice requiring adherence to contractual, rate-of-take provisions. Power generators will have extraordinary difficulty in projecting what the cost of dispatching a gas-fired unit will be if one variable — the dollar impact of penalties that may or may not be imposed, depending upon conditions over which the pover generator has no control — cannot be predicted in advance. Prudence may well require that the power generator assume some level of penalty incurrence in establishing the overall cost of dispatching the unit. Where this is the case, the variable cost of gas will increase significantly, and as a result, gas will fall down the dispatching queue. This result is contrary to the natural gas industry's interest in expanding the use of gas for power generation. Inadequate Tolerances Governing Discrepancies Between Scheduled and Actual Takes and Between Receipts and Deliveries Are Inconsistent with the Needs of Power Generation Loads. Power generators subject to economic dispatch — which brings plants on- and off-line to meet load, as a function of weather and the availability of "ther generating resources — ordinarily cannot predict the precise moment at which they may be required to begin taking gas or may be required to cease their gas use at a particular unit. Nor can power generators typically predict precisely when they will be required to change the run level of a unit (i.e., the level of plant operation required to produce a particular level of electrical output).

Most interstate pipelines have for some time required their transportation customers to maintain a relative balance between volumes of gas received into the pipeline and volumes of gas delivered out of the pipeline for each shipper's account.12 Thus far, FERC has rejected proposals to implement tolerance levels in the 4-5 percent range, instead permitting pipelines to impose (1) a daily scheduling tolerance {relating to the difference between scheduled and actual deliveries) of 10 percent13 and (2) a monthly balancing tolerance (relating to discrepancies between actual receipts and actual deliveries at month's end) of 5 percent.14 FERC has permitted at least one pipeline to require a relative balance between confirmed nominations and actual flows.15 On some days the operator of the gas-fired units depicted in Graph No. 3 would not be capable of nominating and scheduling gas within 10 percent of the take it would actually experience on a given day. There would be days on which that operator would not Jbe able to limit its takes to plus or minus 10 percent of the gas received by the pipeline in a given day.

17 A power generator's failure to meet the prescribed tolerances can expose it to substantial penalties. FERC's general policy is to apply to quantities in excess of the daily scheduling tolerance level the interruptible rate applicable to the service involved.16 Under this policy, for example, Tennessee Gas Pipeline Company's penalty for daily variances exceeding the greater of 10 percent of the scheduled volume or 1000 dth is $0.6362 per dth.17 That is, a power generator whose takes on the Tennessee system were to exceed or fall short of the daily scheduling tolerance would find, after the fact, that the cost of gas it had already consumed was 64 cents higher (per dth exceeding the tolerance level) than the price assumed when the unit that consumed the gas was committed and dispatched. Economic dispatch becomes considerably more difficult when the unit that was dispatched can be rendered uneconomic, retroactively.

Rigid Imbalance an*. Scheduling Penalties Can Render Power Generators' Paa of Gas Uneconomic. Natural gas is not the only fuel available for power yeneration applications. Gas must compete both for entry into power generation markets at the time of plant construction or plant retrofit and for a place in electric utilities' dispatching queues on each and every day. The various constituents of the natural gas industry and, indeed, our nation's energy strategy, now assume that gas will often prevail in such competition. Indeed, FERC itself has adopted policies in Order No. 636 that are intended to "maximize pipeline throughput over time by allowing gas to compete with alternate fuels on a timely basis as the prices of alternate fuels change," in accordance with its view that "it is in the national interest to promote the use of clean and abundant natural gas over alternate ruels such as foreign oil."18 Inflexible and indiscriminate application of penalty provisions will reduce the chances that, in the case of power generation, gas will live up to its advance billings.

Economic dispatch principles followed by virtually all electric utilities place generating units in line for dispatch largely on the basis of the variable cost of running each unit. Factors tending to increase the cost of using gas relative to alternatives such as coal or oil will necessarily drive gas-fired facilities down in dispatching priority. Thus, even where gas has obtained a foothold in a given market, its use on a day-to-day basis is a function of its delivered price relative to the delivered price of competing fuels. Electric generators faced with harsh, non-cost based penalties will adopt strategies for avoiding those penalties that will reduce gas use. For example, an electric generator with the ability to co-fire oil anri natural gas may be forced to maintain a significant amount of oil consumption in order to be able to react to changes in load without affecting its gas consumption. Or utilities may be forced to keep a significant amount of gas generation out of service but available in order to be able to utilize excess gas in 18 the event of a forced outage of another gas-fired generator. Neither of these alternatives is economically attractive. The inflexible application of scheduling, imbalance and hourly take penalties can dramatically drive up the cost of using gas as a power generation fuel. When this happens, and even where this is merely a reasonable possibility, gas will lose relative to alternatives. A gas-fired unit whose total variable cost of consuming gas is $2.75 per MMBtu will lose out to a comparable oil- or coal-fired unit whose variable cost of fuel is $3.25 per MMBtu, where there is a reasonable chance that penalties will increase tha variable cost of using gas by $0.60 or more per MMBtu (an entirely plausible scenario given the level of the penalty being proposed by, for example, Tennessee). The penalty that would have been charged the utility depicted in Graph No. 1 for failure to take in uniform hourly quantities on the peak day would have amounted to approximately $0.40/MMBtu, or approximately 20% of the fuel cost for that day. Of course, the impact of a scheduling or imbalance penalty only becomes clear after the fact. Given this, power generators typically will have no basis whatsoever upon which to predict accurately what their cost of using gas will be, given the many different penalties that could be applied under specific circumstances. So, even though power generation is viewed as th« greatest growth opportunity available to the natural gas industry, and even though national environmental policy, low capital costs and quick construction times favor gas-fired generation, pipelines1 insistence upon tight tolerances, inflexible penalty triggers and substantial penalty dollar amounts could seriously impede the use of gas in existing facilities and could deter commitments to us* gas in new facilities. A Possible Solution: Penalty and Tolerance Provisions Should B« Guided by iri~eiples Calculated to Strike an Appropriate Balance Between Power Generator?" Needs for Flexibility and Pipelines' Needs to Ensure Adequate Service If gas is to have a fair opportunity to increase its penetration of power generation markets, the various constituents of the natural gas industry, power generators and FERC will have to work to ensure that operating tolerances and penalty provisions will not so constrain power generators' ability to use gas as e\ectric system conditions require, or render the final cost of gas consumed so uncertain, that alternatives appear to present less operating and economic risk. To this end, operational tolerances and penalty provisions should attempt to strike a reasonable balance between the legitimate operational and economic needs of the pipelines, on the one hand, and shippers, on the other. Just as "it is essential to an efficient open-access transportation service that the pipelines impose only legitimate 19

-. •) and reasonable operational conditions in which all shippers have had advance notice,"19 it is imperative to the continued use of natural gas as a power generation fuel that operational tolerances and penalty provisions embody the least restrictive means of achieving a pipeline's legitimate operational objectives. Ideally, pipelines' tariff provisions addressing operating tolerances and establishing penalties for exceeding these tolerances should be informed by the following principles: First, the "tightness" of a tolerance should ba a function of conditions on a given pipeline system at a given time. In non-peak conditions, when system operators have the ability to adjust system operations over a broad range without impairing deliveries to high priority loads, tolerances should be relaxed. Approaches to the problem which vary the applicable tolerances depending on whether the pipeline is under stress offer a promising way of achieving this ideal.20 Second, operating tolerances, when needed, must be realistically achievable, given the available and installed metering and flow control technology and error inherent in a given pipeline's system. There must be a de minimis threshold below which imbalances will not count towards penalties or imbalance settlement procedures such as "cash-in, cash-out" mechanisms (i.e., an imbalance l^vel of 4 percent should be considered unacceptably tight). Third, penalties, vhen necessary, should bear a rational relationship to the harm they are intended to prevent. Penalties should be the exception, not the rule. They should only be assessed against (i) conduct constituting deliberate "gaming" of a particular pipeline system,21 or (ii) conduct that could threaten the integrity of the pipeline or could result in the interruption of service to higher priority loads. Where a particular course of conduct does not threaten the integrity of a pipeline system, customers exceeding appropriate tolerances should not be "penalized," but rather assessed an appropriate cost-based rate. Where all that particular conduct requires is the incurrence of additional costs (e.g., additional compressor run time or withdrawals from storage), those costs, not a penalty, should be charged. Fourth, a "no harm, no foul" rule should control the actual imposition of penalties. Where an imbalance, a scheduling error, a deviation from uniform hourly take requirements or an overrun will present no problem for the system (e.g., in non-peak periods when adequate capacity exists and line pack is not threatened), no penalty should apply. The emphasis on daily and even hourly penalties is misplaced; scheduling and hourly flow requirements are needlessly restrictive and can be justified only in periods of severe system stress.

20 Fifth, shippers should be given * reasonable opportunity to confers their conduct to system requirements. So, for example, where system conditions require that tighter tolerances be observed, pipelines should be required to notify their shippers of this fact. When shippers have been notified that a "foul" could lead to "harm," they might be placed on notice that a penalty schedule would apply to instances in which the required tolerances were not observed.22 Customers should be given whatever leeway pipelines can afford to mitigate the burden of their conduct on the pipeline system. Thus, for example, customers should be encouraged to undertake initiatives that minimiEe the buildup of imbalances on a pipeline system. Contractual swapping of imbalances, therefore, as well as netting out of imbalances arising under separate contracts, should be declared to be legitimate tactics for minimizing costs to all concerned, and should be encouraged by a pipeline's imbalance tariff provisions. Sixth, penalties should be the rare exception, not the general rule. Therefore/ penalties should not be a source of any profit whatsoever to the pipeline. Pipelines should have no incentive to find reasons to impose penalties; indeed, they should have every incentive to avoid their imposition whenever possible. Penalty revenues in excess of the revenues required to defray costs associated with a particular transgression should be credited to non-offending customers. Finally, penalty provisions must not be set in stone. Circumstances faced by pipelines change over time. Construction may alleviate a bottleneck which today requires the imposition of a tight tolerance or a severe limitation on hourly take variability. Additionally, the nature of a pipeline's load profile may change such that a pipeline is better equipped to deal with unanticipated swings in demand (perhaps because additional storage capacity has been added). Pipelines should believe themselves to be under a continuing obligation to reflect the elimination of an operational constraint in more liberal operational tolerances and reduced penalty levels once the constraint has been eliminated or eased. After all, with experience the industry may develop better ways than are reflected in "command and control" penalty provisions to deal with operational concerns. A Mid-Course Evaluation: How Are Power Generators Faring in the Interstate Pipeline Restructuring Wars? Although its self-imposed November 199 3 restructuring deadline is closing rapidly, FERC has completed the cycle of restructuring proposal/initial FERC order/compliance filing/FERC order on compliance filing and rehearing in only a handful of interstate pipeline Order No. 636 cases. still, some trends are emerging. Among these, some are mildly favorable to power generators; many 21 are not. (An addendum to this paper summarizes the operational standards and penalty provisions on which FERC seems to be converging.) FERC Giveth... Early restructuring orders have demonstrated some FERC solicitude for the operational concerns raised by power generators. Although it has generally permitted pipelines to include in their "restructured" tariffs the sorts of hourly, daily and monthly tolerances described above, FERC has balked at proposed balancing and other tolerances that would be more restrictive than those included in pipelines1 pre-restructuring tariffs.23 FERC has "limited" the scheduling penalty, i.e., the penalty that applies to discrepancies between scheduled and actual deliveries, to the interruptible transportation rate for comparable service.24 It has even encouraged (but not required) pipelines to consider "whether penalties for imbalances from scheduled quantities are in fact necessary to maintain system integrity at all times and whether the proposed level of the penalties for such imbalances is appropriate."25 FERC has noted with approval tariff provisions that permit "intra-day" changes in scheduling for gas delivered in the same day, albeit on a "best efforts" basis, endorsing the notion that affording shippers flexibility to change scheduled gas deliveries during the gas day will enable them to avoid penalties. Widespread concerns noted sympathetically by FERC contributed to Texas Eastern's decision to withdraw its proposed $25 per dth overrun charge.27

As for the contentious issues relating to monthly imbalance tolerance levels and "cash-out" imbalance resolution mechanisms, FERC has struck some glancing blows in favor of flexibility. While it has generally approved such proposed mechanisms, FERC has r^uired pipelines to pro 'ide for the "netting" of imbalances on a shipper-by-shipper, service-by-service basis, and to provide that the degree of deviation from the tolerance level be determined only afteir such netting.28 It has generally declined to permit pipelines to "buy low, sell high" by charging the highest spot price for cash-out penalties due the pipeline while paying the lowest spot price for cash-out penalties due customers.2' It has also generally required that cash-outs be based on actual volumes out of balance, rather than on the difference between scheduled volumes and actual volumes30 (one pipeline has, however, been permitted to apply cash-out imbalances on the difference between confirmed nominations and actual flows).31

Perhaps most encouraging to power generators was FERC's declaration of its interest in the operational concerns they and, in particular, the Ad Hoc Group of Power Generators,3^ had advanced in several restructuring proceedings. In the Texas Eastern Restructuring Order, FERC stated that it "finds merit" in the arguments concerning operational limitations and penalty provisions raised by power generator representatives, and "announce[d] its intention to convene an industry-wide conference 22 this coining spring to address further parties' concerns with, inter alia, scheduling penalties and tolerance levels, and curtailment provisions."33 This pronouncement suggested that power generators would be provided a further opportunity to describe their special needs and to propose alternative means of meeting pipelines' operational control requirements. And PERC Taketfa Away. Although FERC has been willing to urge pipelines in the direction of s bit more operational flexibility, it has not addressed the fundamental concerns advanced by power generators in any meaningful way. While professing interest in power generators' arguments favoring flexibility, FERC has nevertheless approved most aspects of pipelines' operational proposals without requiring proof that specific limitations are actually needed, over often detailed presentations describing the problems with inflexible tariff proposals.34 It has held up the flexibility-enhancing features of "no-notice" transportation service as largely responsive to power generators' concerns regarding tolerances and penalties, even while admitting that such service will generally not be available to power generators.35 It has gone on to mischaracterize, and then dismiss summarily, some of the power generators' concerns, stating that it "disagrees with the notion that because an end-user's load requirements may vary from hour-to-hour, it should be permitted to change its deliveries with impunity from [sic] penalties."36 If this is all the consideration power generators can expect from FERC as to their operational concerns, power generators can expect to have little success in obtaining the sorts of operational concessions they will require if gas is to increase its penetration of the market.

FERCs handling of some of the details of pipelines' operational proposals is hardly any more encouraging from the power generator perspective. It has "rejected arguments that would limit the imposition of penalties when real time information was not available."37 So, even where a pipeline — not to mention a shipper — is not in a position to evalua^e its penalty situation as it develops, penalties may nevertheless be assessed after the fact.38 FERC has rejected power generator requests that it require pipelines to permit an "in-kind" makeup period to cure end- of-month imbalances, 9 and has declined to permit netting of imbalances among shippers.40 It has dismissed concerns regarding the feasibility of maintaining the uniform hourly rates of take pipelines seem poised to enforce.41 It has permitted one pipeline to impose penalties on the basis of discrepancies between confirmed nominations and actual flows, over strident power generator objections.42 It has refused to require pipelines to credit back to firm shippers revenues generated by scheduling and similar penalties,43 thereby raising the possibility that penalty revenue collection will become a profit center for pipelines. Pex~haps vnost ominously from the power generator perspective, FERC has rejected the proposition that penalties should b» imposed 23 only when there is some demonstrable harm to the pipeline system involved, in FERC's view, "penalties are not to be applied only in situations where the pipeline can demonstrate harm. Penalties may be applied to deter conduct that may adversely affect the ops'.ation of the pipeline system."44 So much for the principle of "no harm, no foul." FERC and, for that matter, the pipeline industry, seem to have concluded that the interest in the "maintenance of discipline" on pipeline systems by way of command-and-control provisions (l) cannot be met through any less restrictive means than rigid tolerances and substantial penalties, inflexibly applied and (2) is to be preferred over shipper interests in obtaining transportation service that can conform to the requirements of variable loads at a predictable cost.

CONCLUSION The restructuring of the interstate natural gas industry mandated by Order No. 636 is tar from concluded. There remain opportunities for the pipelines and FERC to respond to the operational and economic concerns of power generators in ways that will make additional gas use easier and less risky.45 A newly constituted FERC may take a more sympathetic view toward the needs of power generator loads than is reflected in FERC restructuring orders to date. Pipelines may note with dismay that the sort of uncertainty injected by imposition of after-the-fact penalties can indeed result in power generation loads not being dispatched (meaning less pipeline throughput) or gas-fired power generation capacity additions not being undertaken, perhaps drawing a lesson from the adverse impact on dispatch currently resulting from the April run-up in natural gas prices.

Alternatively, FERC and the natural gas industry might choose to do nothing, content with the status quo and a regulatory environment in which pipelines are insulated from operating risk and from the need to work hard to serve challenging load. If this course is the one chosen, the growth the gas industry confidently predicts for power generation use of natural gas will be difficult indeed to achieve.

24 t. r«ifa» *-fff m «*lje*rino; Qrdar, sjjjtf at 170-173 (a{t)ha need xxnuseu cms for this provision la based not on tha ability to xonitor gaa flova but on tha naad to restrict gaa •crsaenta. Evsn If Taitaa taatarn lacks tb* tbULtj at tula tiaa %o •onitor tucii action*, ofl* tmmaama ebllgatlou to crcvlda for ald-sonth aaJcaup volos«a and ald-sonth !• |Hi •*£«.( "•• Research Institute, Ifltl Baseline projection of tut th« cuatoawr will act in good faith vhtn fac«d with tha naad i bt At") 0.0. Enarey BupplY ana Danand (riliiwd Aiaj. Iff. l»M) (concluding for flow restriction*'f. Jaj a I an alpemoq^n C«a yt>r«ylaa^pn Ca.. that ant of tha projected growth and dsiand for fteru-al gas Mill 43 me (CCS) 1 »1,133 at «l,II7-H (fab. li, lf»]> (approving 16. in, «*su, »*rft»v»a bhaarlng Ordar. mi^ia at 80 ("our «ccur in tA« elsetrio gswation iwur) i aCfl/H*ql«r, billy, Ino., "contractual rtta-of-flow* tariff" provision). currant policy () aats tb» «cha» Caa Plgallna Co.. S3 TOIC tCCH) • 61,350 in lta exletijsg tariff), ffl'fl iinJJti. « rW at . aJxta at a 63 FEHC (CCM) f, SI.000 (April 33, (March 16, 1993). lills at 7i-9 ( (b)acauaa OBAs (Oparatlonal •*6-77. Smm ai^o T*1^^ t»«ttm ftuiaarlog ordar, O ftBc at , Raftering Crc"«r"j. Balancing Agraamants] will ba ajndatary an its systia, va will •t»«-3 at 16S (-Tezas Eastern1* propoaad flvs percent tolerance approve Tannassaa's proposal to apply caah-outa (ale] lmhalancaa en level 1« inccrtslscant vith ths Coaalasion

34. 3u, BVOJ., Ta»aa fj«tarn 'iah«arlnq Ordsr, fa rate at , ftlfjU at 193 (citing Panh.ivii. juhaarlng Omar, S3 PERC at ~ " , 34. £u, e,,B,. Taigs Etatrxn Rahaarlnq order, 41 rZXC at •laifl *t 14), •laeo at 173 (approving operational lialtatlons «J*3 penalty provisions that have y«t to be tested* reflnosjits can bs sada 33. Panhandle Rehearing Order, «J me at , llMfl at to foliowinq 1 trial period a! operations under the rasiructnrsd (Quoting TrimwiKim Ptu.Hn. rn 6l PE2C~ (cof) 1 61.333 at 62,360-61 (1993)). tariff).

M rgZL 4t 38- Jdj., 63 TEBC at , al«aa at 60. ajj alaa Tannaaiaa Caa 33. fit* ii*.' ' lAwfl *t 174 ("[t]he Onai**ton Plpalln* Co.. S3 FEBC 1 6l,aS0 st , ilpo at «l-«3 (raqyirlng agrees that Taxae Castarn's no-notlca carvice Ifc fully subscribed Tannasoaa to rataln existing provision p*raittlng sld-day at this tlu. Howavar, Us service n«* a qanmral availability provision and asy be contracted far by any party should additional capacity t*cawm available, so-notica service ofZara the degrea °t Rehearing Ordar, 43 TOLC at flexibility these cuatosers s*«k, but also rsflscta th* coat of providing that flexibility-).

Rahaarln? Order. e2 FEKC at at . _, slats 37. paphandla Rahaaring ord*r, «3 PtBC at , ajjao at |3. 39. Texas Kaatarn Raatructurlng Ocdar, SJ PEKC at 61.116-17, aUtQ •t 101 (characterlilnq the use of different spot prico Indlcaa for it. Sit- t-9- r 7Mf* Eastern Rehearing ordar, 63 ftSC at , eash-outs depending on whether the pipeline in buyinq or sailing alua *t 173 (denying rehearing request that Texas Eaatarn "be "inherently unfair-). barred i*roa ordsr ing unifant hourly daliyary, <,. until aucn tlse *» It has Lne ability to Monitor such gaa flows"). 30. Tait»a ta|tara Reatructurlng Ordar, 63 tOLC at «1,116-17, eleao nt 101-03] fwaa >«»t*m Rshearlng ordar, 63 FK»C at , nUu 39. E.a.. panhandia Rshaaring Order, *3 FE31C at , aiJlfl at

40. E.g.. Id. • «3 fERC at , s,lsaQ at 93. 6 1 (beceuse operational salanclnq Agrseaent* will" "iandatory *n tJie Tmmaase* syetea). 41. Eifl*, Taxaa Eastern Rehasrlng Order, «3 FEKC at . aiuta at 173; *,*.* slsa AlgonT"1?! f**> *rrangml*aloT< Ca.. S3 FERC (CQt) 33. The Ad Hoc Croup of Power Ceneratora represent* - -dlvarce 1 61,133 at 61,lf7-ie (Fab. 11, IK}), llUQ *C 4«-97. group of electric utilities and tae nwX Manager* Assoclat trade organisation concerned with the Interests oitionf . a 43. Tannaaaae Cia Pipeline Ca*. 62 FESC st , ajsaq at 71-79. procursB4nt-rel*t»d Issus* facing ncn-utllity power gsnsratorfue-l Haebars of th A Ad Boo Croup •'.; tha tiaa of the group'* ir.iclal 43. Z.o*. panhin^le Keneering Order, 83 FDiC at , aiata «t tiling in tfi» XlXULAUfilZH restructuring docket include) Aaerlcan • 7 ("[o]th.er than Cor penaltias attributable to aEfTHitu and cats tlsctrlc Povar 3#*vlc* corporation, Aritona Puflic Service Coapany, outs. It has been our policy not to require th* creditl*? of Atlantic City Electric Coapany, Beaton tdiscm Company, Entarqy penalty revenues'*. Serylcsa, Inc,, (r»pr*»*nting Ariunaas powar t Light Cospany, Louisiana p«ar t Ught coapany. nlselsaippi Povar t Ught coapany 44. ZJj., S3 ttSC at ^^^ , aius at «1-«1. «nd Haw Orleans Public Service, Inc.), fu-l Hanagars Asaociation K*w England Povar service company, Bortharn state* power Coapany, 45. So»e pipelines have. In fact, been quite solicitous of paver Hortheast utilities, Potoaae Electric Powar Coapeny, Southern genarstor concerns. Included in tfila Rukber are Florida Cas coapany Sarvicss inc. fa* *7ene for AIMMMM Povmr Company, Georgia Transalsslon Company and Iroquo'* uss Transaicsion Systes, L.P., Power company, Hlsals^ipp1 n i 1 Ptswact icr coitpant Cty anpanyd Savanna v h Electric t both of which have substantial power jansratlon load and hav* fcor.d !2)(*B^?'^2l^J!) "- 5 2 * ^m , * ' tr9ini* Hactric ways of avatlnt} powar gennrators1 needs far flexibility {notwithstanding thslr I*^k of on-systaa storage capacity) •

33. Texaa Fas,taiTi Restructuring Ordar, «3 FEKC at 61,119.

31