Deliverability on the Interstate Natural Gas Pipeline System

Transcription

1 DOE/EIA-0618(98) Distribution Category UC-950 Deliverability on the Interstate Natural Gas Pipeline System May 1998 This report was prepared by the, the independent statistial and analytial ageny within the Department of Energy. The information ontained herein should not be onstrued as advoating or refleting any poliy position of the Department of Energy or any other organization.

2 Prefae Administration (EIA), Form EIA-176, Annual Report of examines the apability of the national pipeline grid to Natural and Supplemental Gas Supply and Disposition ; and transport natural gas to various U.S. markets. The report (5) Form EIA-191, Underground Natural Gas Storage quantifies the apaity levels and utilization rates of major Report. Complementary data were obtained primarily from interstate pipeline ompanies in 1996 and the hanges sine the EIA, Natural Gas Annual 1996, DOE/EIA-0131(96) or 1990, as well as hanges in markets and end-use onsumption earlier issues. patterns. It also disusses the effets of proposed apaity expansions on apaity levels. was prepared by the EIA, Offie of Oil and Gas, under the The report onsists of five hapters, several appendies, and diretion of Kenneth A. Vagts (202/ ). General a glossary. Chapter 1 disusses some of the operational and information onerning this report may be obtained from Joan regulatory features of the U.S. interstate pipeline system and E. Heinkel (202/ ), Diretor of the Natural Gas how they affet overall system design, system utilization, and Division. Detailed questions on speifi setions of the apaity expansions. Chapter 2 looks at how the exploration, publiation may be addressed to the following analysts: development, and prodution of natural gas within North Ameria is linked to the national pipeline grid. Chapter 3 Chapter 1. Introdution, James Tobin (202/ ). examines the apability of the interstate natural gas pipeline network to link prodution areas to market areas, on the basis Chapter 2. Aess to Supplies and Prodution Regions, of apaity and usage levels along 10 orridors. The hapter William A. Trapmann (202/ ). also examines apaity expansions that have ourred sine 1990 along eah orridor and the potential impat of proposed Chapter 3. Deliverability on the Interstate Network, new apaity. James Tobin. Chapter 4 disusses the last step in the transportation hain, Chapter 4. Deliverability to Markets, James Tobin. that is, deliverability to the ultimate end user. Flow patterns into and out of eah market region are disussed, as well as the movement of natural gas between States in eah region. Chapter 5. Aess to Transportation Markets, Barbara Mariner-Volpe (202/ ) and Mary E. Carlson Chapter 5 examines how shippers reserve interstate pipeline (202/ ). apaity in the urrent transportation marketplae and how pipeline ompanies are handling the seondary market for The overall sope and ontent of the report was supervised by short-term unused apaity. Four appendies provide James Tobin. Overall oordination of the report was provided supporting data and additional detail on the methodology used by James Thompson. Signifiant analytial ontributions were to estimate apaity. made by the following individuals: The main data soures (see Appendix D) used for the analysis Jay K. Mithell Chapter 2 inlude: (1) annual apaity reports and aompanying Format 567, System Flow Diagrams, filed with the Federal Mihael J. Tita Chapter 5 Energy Regulatory Commission (FERC) by major interstate pipeline ompanies (18 CFR and 260.8); (2) FERC Lillian H. Willie Young Chapter 3. Form 11, Natural Gas Pipeline Monthly Statement (1995 and earlier years); (3) FERC Form 2, Annual Report of Desktop publishing support was provided by Margareta Major Natural Gas Companies ; (4) Energy Information Bennett. iii

3 Contents Exeutive Summary... vii 1. Introdution... 1 Report Purpose and Struture... 1 Defining Deliverability... 2 Shipper Requirements... 4 Transmission System Design... 5 Pipeline Utilization... 7 Capaity Expansion Aess to Supplies and Prodution Areas U.S. Natural Gas Supplies by Region, Reeipt Capabilities Summary Deliverability on the Interstate Network Reent Changes Affeting the Pipeline Network System Growth Sine Major Transportation Corridors Summary Deliverability to Markets Major Market Changes, Regional Overviews Outlook Aess to Transportation Markets Estimating Capaity Availability Transportation Market Ativity Charateristis of Firm Capaity Held by Different Types of Shippers Summary Appendies A. State-to-State Natural Gas Pipeline Capaity and Usage Levels B. Natural Gas Pipeline and System Expansions, C. Changes in Natural Gas Markets D. Data Soures Glossary Page v

4 Tables 1. Forty Largest Interstate Pipeline Companies by Level of Deliverability, Natural Gas Prodution and Supplies in the Lower 48 States, by Region, Lower 48 Dry Natural Gas Proved Reserves and Reserves-to-Prodution Ratio, Central and Western Gulf of Mexio Lease Sales Before and After the Royalty Relief At Top 10 Fields in the Lower 48 States Ranked by Natural Gas Prodution, U.S. Natural Gas Produtive Capaity Utilization and Surplus Deliverability by Region, 1990, 1995, and Interregional Pipeline Export Capaity, Average Daily Flows, and Usage Rates, 1990 and Natural Gas Transportation Corridors and Assoiated Major Pipeline Systems, Interregional Pipeline Capaity, Average Daily Flows, and Usage Rates, 1990 and Regional Weather and Gas Storage Profile, Regional Energy Profile Comparison of Annual Average Change, or Regional Natural Gas Customer Market Share Changes, Regional Natural Gas Customers, Average Annual Change, Reserved Firm Transportation Capaity by Region, July 1996 and January Charateristis of Firm Contrat Capaity as of April 1, 1997, by Shipper Figures 1. Generalized Shemati of Natural Gas Pipeline Transmission Major Natural Gas Produing Basins and Transportation Routes to Market Areas Lower 48 Natural Gas Prodution by Region, U.S. Coalbed Methane Output, Comparison of Average U.S. Natural Gas Wellhead Prie and Canadian Natural Gas Import Prie, Canadian Gas Exports to the United States and Total Canadian Gas Prodution, Finding Costs for Natural Gas and Crude Oil, Offshore and Onshore Prodution Costs for Natural Gas and Crude Oil, 1995 and Depth Reords in Deep Water Gulf Drilling Capaity of New Natural Gas Pipeline Systems Plaed in Servie in the United States Between 1990 and Region-to-Region Natural Gas Pipeline Capaity, 1990 and Major Natural Gas Transportation Corridors in the United States and Canada, Net Natural Gas Pipeline Capaity Entering (-Exiting) Eah Region, Deember Interstate Natural Gas Capaity Summary for the Central Region, Interstate Natural Gas Capaity Summary for the Midwest Region, Interstate Natural Gas Capaity Summary for the Northeast Region, Interstate Natural Gas Capaity Summary for the Southeast Region, Interstate Natural Gas Capaity Summary for the Southwest Region, Interstate Natural Gas Capaity Summary for the Western Region, Relationship of Capaity and Utilization Conentration of Reserved Firm Capaity by Region, April 1996 April Growth in the Capaity Release Market, November 1993 Marh Capaity Held by Replaement Shippers, by Region and Heating Years, Capaity Held by Replaement Shippers During the Nonheating and Heating Seasons, by Region Natural Gas Pipeline Throughput Under Firm and Interruptible Servie, January 1996 September Share of Total Firm Capaity Held on April 1, 1997, by Type of Shipper Average Length of Long-Term Firm Contrats as of April 1, Average Length of Short-Term Firm Contrats, January and April Average Firm Capaity per Contrat as of April 1, Share of Regional Firm Capaity as of April 1, 1997, by Shipper for Seleted Regions Capaity Under New and Expiring Firm Contrats, April 1, 1996 April 1, Reserved, Utilized, and Available Capaity for the Heating Year vi

5 Exeutive Summary inrease in pipeline apaity, would seem to indiate that examines the apability of the interstate pipeline network to demand for natural gas was growing faster than new move natural gas to various markets within the United States, apaity was being added and that, in some areas, highlighting the hanges that have ourred sine oasional bottleneks or periodi apaity onstraints Signifiant hanges have ourred in the natural gas industry might have ourred or were developing. In other areas, sine the (EIA) published the inrease in pipeline usage rates simply refleted a 1 the predeessor to this report in Fundamental hanges greater use of existing apaity that had been previously in industry struture were imposed with the issuane of Order underutilized beause of overbuilding or a temporary 636 in 1992 by the Federal Energy Regulatory Commission dropoff in demand. that allowed market fores and ompetition to beome the primary fators influening hange in the natural gas Refleting its growing role in the U.S. natural gas marketplae. Several new onepts in natural gas trading and market, Canadian import apaity into the United distribution have developed, suh as the market enter, and States inreased by 69 perent, or 4.5 billion ubi feet hanges have been made in how ertain network resoures are per day. It also represents the largest portion of new being used in support of these system hanges, suh as open interregional pipeline apaity proposed for development aess to underground storage apaity. during the next several years. Although it is unlikely that For the most part, these hanges have been positive. Total all projets will be built, more than 7.7 Bf per day of import apaity expansion has been proposed, most of it U.S. natural gas onsumption has inreased by 17 perent feeding into the U.S. Midwest and Northeast regions. To sine 1990, marketed prodution has inreased by 6 perent, a great degree, the proposals are driven by produers in net imports have nearly doubled, and the interstate pipeline Western Canada seeking markets for that region s system has inreased in size and apability. Overall growth in expanding prodution apability. Plans to develop fields the pipeline network has ourred in both its deliverability in the Sable Island area off the east oast of Canada have and usage levels. For instane, between 1990 and the end of also triggered a need to find markets for that prodution 1996: as well. (Between 1990 and 1996, Canadian marketed natural gas prodution inreased at an 8-perent annual Deliverability (apaity) on the interstate pipeline rate, while natural gas end-use onsumption in Canada system inreased by more than 15 perent, or inreased at only a 3.5-perent rate, thus the desire to 10.9 billion ubi feet per day, at regional borders expand export apabilities.) (Table ES1). The largest inrease in interregional deliverability was to the Western Region, with an Growth and hanges in deliverability on the natural gas additional 3.2 billion ubi feet (Bf) per day, or network have also resulted in some shifts in transportation 45 perent (Figure ES1). The seond largest inrease was orridors and aess to prodution areas. Deliverability out of 2.4 Bf per day, 24 perent, into the Northeast Region. the Roky Mountain area is inreasing as produers there are The development of so muh apaity in the West led to seeking ustomers in expanding markets, suh as the U.S. a surplus of apaity and an overall drop in the pipeline Midwest, to supplement their traditional markets in the apaity usage rate, whereas in the Northeast, demand Western Region. Likewise, produers and pipeline ompanies growth fully supported the inrease. In fat, pipelines in the areas of West Texas and New Mexio have also shifted into the Northeast saw a substantial inrease in average a larger portion of their apabilities toward Eastern markets. daily usage rates, up 6 perentage points from 1990 levels. In 1997, at least 41 natural gas pipeline projets were ompleted and plaed in servie in the United States, adding Pipeline utilization rates also inreased, by 6.3 Bf per day of apaity overall, with 0.5 Bf per day of 7 perentage points, reahing a high of 75 perent (on that representing added interregional deliverability and an average day) in This inrease in interregional 3.9 Bf intraregional deliverability (Table ES1). A major pipeline use, ourring simultaneously with a major portion of the new pipeline apaity represented inreased reeipt apability in expanding supply regions. For instane, the largest projets were in the Gulf of Mexio (3.2 Bf per day) as offshore and deep-water development efforts in the area ontinue to expand. In addition, several major projets were ompleted that expanded aess to the Wind River and, Capaity and Servie on the 1 Interstate Natural Gas Pipeline System 1990: Regional Profiles and Analyses, DOE/EIA-0556 (Washington, DC, June 1992). vii

6 Table ES1. Regional Summary of Changes in Interstate Pipeline Capaity, , and Planned Additions, a Entering the Region (MMf/d) b Within the Region (MMf/d) Estimated Proposed Perent Estimated Proposed Perent Capaity Capaity Perent Capaity Additions Change Capaity Capaity Perent Capaity Additions Change End of End of Change Added in to Capaity End of End of Change Added in to Capaity Region Central... 11,824 12, , ,754 23, ,143 1,081 9 Midwest... 22,818 24, , ,354 23, , Northeast... 10,009 12, , ,261 32, , Southeast... 19,914 21, ,788 51, ,999 5 Southwest... 2,048 2, ,583 45, ,341 1,461 8 Western... 7,126 10, ,924 15, U.S. Total... 73,739 84, , , , ,874 12,492 9 Canada... 1,277 2, , NA NA NA NA NA NA Mexio , NA NA NA NA NA NA a Inludes only the sum of apaity levels for the States and Canadian Provines bounding the respetive region. b Represents the sum of the interstate pipeline apaity, or planned apaity, on a State-to-State basis as measured at individual State border rossing points, exlusive of apaities Entering the Region. Does not inlude projets that are entirely within one State. Gulf of Mexio projets are onsidered within the Southwest or Southeast region. Proposed apaity has been ounted in only one region even though some projets may ross regional boundaries. In the ase of a new line, the additional apaity has been inluded within the region in whih it terminates. For an expansion projet, the added apaity is inluded in the region where most of the expansion effort is foused. MMf/d = Million ubi feet per day. NA = Not available. D Soures: Capaity: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember Capaity Additions: EIAGIS-NG Geographi Information System, Natural Gas Pipeline Constrution Database, as of Marh 1998, ompiled from Federal Energy Regulatory Commission, Natural Gas At Setion 7() Filings, "Appliation for Certifiate of Publi Conveniene and Neessity," and various natural gas industry news soures. Figure ES1. Region-to-Region Natural Gas Pipeline Capaity, 1990 and 1996 (Volumes in Million Cubi Feet per Day) Western 3,786 (2,421) 45% 298 (250) 19% 1,194 (365) 227% 2,114 (1,283) 64% Central 66 (66) 0% 1,563 (1,254) 25% Midwest 2,354 (1,765) 33% 9,879 (8,988) 9% 3,049 (2,161) 41% 2,543 (1,211) 110% 4,887 (4,584) 7% 2,038 (2,024) 1% Northeast 2,393 (467) 412% 520 (100) 418% 45 (45) 0% NN = 1996 (NN) = 1990 N% = Perent Change 5,351 (4,340) 23% Southwest 350 (350) 0% 8,609 (8,555) 1% 844 (354) 138% 20,846 (19,801) 5% 9,821 (9,645) 2% 405 (405) 0% 5,149 (4,971) 4% Southeast Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember viii

7 Powder River basins of the Roky Mountain area by almost from 10 perent. Pratially all salt avern storage sites 0.7 Bf per day. The first new export lines to Mexio to be are aessible from market enters. ompleted in 5 years were also plaed in servie during The inrease in pipeline utilization levels sine 1990 an be Availability of eletroni trading. Another growing attributed in part to new trading and shipping arrangements feature of the new natural gas marketplae is the that evolved with the introdution of pipeline open-aess inreased use of omputer-based eletroni trading. transportation and storage. The inreased opportunities for Although there are only a few dominant systems in this trading, variable routing of gas shipments, and the marketplae, the number of trades onduted via development of new servies to omplement and expedite eletroni trading has grown steadily during the past network operations have done muh to improve the effiieny several years. These systems bring together gas traders, and utilization of available apaity. Several fators an be apaity seller/buyers, and others at a number of optional ited as ontributing to the improvement, inluding: points on the pipeline grid and assist the parties in arrying out their transations. Most of the major market Development of a release market for pipeline enters/hubs in North Ameria, as well as a number of apaity, whereby unused firm apaity an be sublet the most ative spot-market trading points on the pipeline by other shippers. The pipeline apaity release market grid, are aessible to traders. Not to be forgotten, reahed a level of about 3.6 trillion ubi feet in 1996 however, is trading on the non-eletroni spot market, (the equivalent of 16 perent of available apaity). whih still aounts for the large majority of trading Before FERC Order 636, there was only limited ativity overing short-term buying and selling of natural experiene with apaity brokering, whih had been gas. Currently there are more than 120 trading points authorized by the Federal Energy Regulatory within the national pipeline network at whih trading is Commission in onduted by open-market traders. Development of market enters. Sine 1990, when only In the market for pipeline apaity, shippers prefer long-term one formal market enter/hub was operational (the Henry ontrats (a year or more in length) over short-term ontrats Hub in Louisiana), more than 36 market enters have and firm rather than interruptible transportation servies. developed at strategi points within the North Amerian During the 12 months ended Marh 31, 1997, about pipeline grid. These enters have ontributed 78 perent of apaity was reserved under firm transportation signifiantly to providing shippers greater aess to ontrats. However, not all of that apaity was used by the lowest-ost gas supplies. Shippers now use market ontrat holders and, in addition, substantial firm enters for rerouting gas supplies from one pipeline to transportation apaity is unsubsribed and available to another and also for aess to servies, suh as short-term shippers (27 trillion Btu per day, or 21 perent of maximum gas loans and parking, that failitate gas trading and apability in 1997). Although this unommitted apaity may improve pipeline apaity usage. The Henry Hub, the not suit the needs of a partiular shipper beause of its Chiago Center (Illinois), and the Leidy Hub loation or term et., it ould support additional market (Pennsylvania) are the three most ative market enters growth beyond urrent levels. Shippers also have aess to in the United States today. additional transportation servies in whih deliveries may not neessarily be guaranteed by the pipeline ompany. These Improved aess to underground storage. Open aess servies inlude apaity release and interruptible to underground storage servies, mandated in Order 636, transportation servie and are available to shippers depending has also played a large role in improving the quality of on the atual use of the pipeline system by firm transportation transating business on the natural gas pipeline network. ustomers. Marketers are the most ative in the short-term and The major trend in underground storage growth has apaity release markets beause these markets provide the been the inreasing development of high-deliverability flexibility to meet varying and unexpeted demand levels. failities, mostly salt avern sites, whih are designed to permit rapid aess and turnover of stored inventory. These types of sites have beome losely assoiated with market enters as they omplement the short-term Outlook parking and loaning servies offered by these enters. Based upon EIA natural gas onsumption projetions, the Sine 1993, daily deliverability from salt avern and market for natural gas will ontinue to grow steadily into the other types of high-deliverability storage failities has next entury. EIA foreasts about a 2-perent annual growth grown to represent more than 15 perent of total rate during the next 10 years ( ). Exluding demand underground storage daily withdrawal apability, up in the supply areas, this translates into a projeted inrease in onsumption of nearly 1.2 trillion ubi feet by the year ix

8 In fat, the extensive number of urrently planned apaity developing fields off the oast of Eastern Canada (Sable additions and expansion projets indiates that substantial Island) to Canadian and U.S. markets. These expansions ativity is underway to address these potential inreases in de- ould add between 5.9 and 7.0 Bf per day to U.S. import mand. If all the projets urrently proposed through 2000 apaity from Canada during the next 3 years along these were built, interregional apaity would inrease by as muh orridors, an inrease of more than 52 perent over 1997 as 14.7 billion ubi feet (Bf) per day, or about 17 perent, levels. from the level in Additional projets that are limited to providing servie within a speifi region omprise an Current interregional and State-to-State apaity levels, in additional 15.3 Bf per day of apaity. most instanes, appear to be adequate to meet urrent ustomer demands, although in a few instanes average daily Natural gas onsumption is projeted to grow at a 5-perent pipeline utilization rates inreased signifiantly between 1990 annual rate in the Southeast Region through 2008, supported and This rise in usage is a strong indiator that by antiipated growth in eletri utility and industrial markets instanes of peak-period apaity onstraint ould begin to for natural gas. Markets in the Northeast and Midwest are our if demand for natural gas in the affeted markets were projeted to expand at annual rates of only 3.3 and to inrease at a faster rate than expeted. Also, while the 1.6 perent, respetively. Current proposals to expand amount of new apaity proposed for the next several years pipeline apaity into these regions between 1998 and 2000 appears to be adequate, and in some instanes more than amount to the equivalent of about 10.7 Bf per day, with adequate, to meet foreasted demand, there will probably be 5.3 Bf per day direted to the Midwest, 5.0 Bf to the some loal areas with apaity onstraints. Northeast, and 0.4 Bf to the Southeast. The apability of the pipeline network to transport and deliver Based on urrent expansion proposals, the most extensive gas from supply areas to ultimate onsumers has grown development of new apaity during the next several years measurably sine 1990, and the quality and flexibility of will our along the Canadian orridors. At least four new servie has improved as well. Substantial further growth in pipelines and several expansions are planned that will expand system apability is expeted in light of the many expansion deliverability from Canada to the U.S. Midwest and Northeast projets sheduled for ompletion during the next few years. markets and also to Canadian domesti markets. These lines Further integration, improved servies, and more interwill improve aess to natural gas supplies in Western Canada onnetions along the grid should also help aommodate and also reate a new orridor to bring prodution from the antiipated future demand. x

9 1. Introdution The United States has an extensive network of pipelines for Analyze how regulatory hange and market fores sine transporting natural gas from supply areas to all of the lower 1990 have reated new market entities while altering the 48 States. In 1996, this system delivered about 20 trillion traditional role of a number of existing ones. ubi feet of natural gas to end users, an average inrease of 1 about 5 perent annually sine This trend is expeted Charaterize and ompare the various prodution and to ontinue, as (EIA) market areas in relationship to the interstate pipeline projetions indiate that demand ould be near an all-time system. 2 high by the turn of the entury. These projetions of inreasing demand raise important issues for the U.S. pipeline Assess shifts in market and end-use onsumption patterns transmission industry onerning the system's apability to 3 within the different markets between 1990 and move gas, the mehanisms for alloating apaity, and the best way to apportion osts among users to obtain effiient Identify and examine reent proposals for new pipeline use of the system. routes and apaity expansions on existing lines, partiularly their effets on apaity levels. Report Purpose and Struture This report primarily examines the apability of the interstate pipeline network to move natural gas to various markets within the United States. The examination evaluates these apabilities from supply areas to end-use markets, looking first at the produtive apaity and assets of major prodution areas and the ability of the pipeline network to handle urrent and proposed levels of prodution. It then assesses the ability of the mainline pipeline network to transport and diret supplies to end-use markets and the apabilities of the trunklines and regional pipeline systems to deliver gas to the ultimate onsumer. Throughout the report, the data are disussed and analyzed on a regional basis (see Figure ES1) to reflet the signifiantly different profiles of various prodution and market areas within North Ameria that are linked by the pipeline network. The main purposes of this study are to: Quantify the apaity levels and usage of apaity on the interstate pipeline network in 1996 between supply areas and major market areas. Examine the hanges that have ourred on the pipeline network sine 1990, inluding new pipeline systems and expansions to existing systems. The report does not attempt to identify speifi instanes of exess pipeline apaity or system bottleneks. Identifiation of speifi existing apaity onstraints or exesses would require modeling and simulation runs using atual daily operational data. Suh an endeavor would require more detailed and speifi data than were available for this study. This hapter disusses some of the operational and regulatory features of the U.S. interstate pipeline system: the shipper requirements that affet the overall system design, the design proess, the system utilization, and the regulatory proedures for apaity expansion. It also examines the differenes between various types of pipeline ompanies and the importane of underground storage failities in the design and operation of a pipeline system. Chapter 2 looks at how the exploration, development, and prodution of natural gas within North Ameria are linked to the national pipeline grid. The analysis inludes a profile of urrent and, where possible, projeted prodution levels within the major natural gas-produing areas in the United States and Canada. It also examines prodution levels relative to pipeline apaity on pipeline systems exiting these areas and entering the major natural gas transportation orridors serving markets in North Ameria. The apability of the interstate natural gas pipeline network to link prodution areas to market areas is examined in Chapter 3, based on apaity and usage levels along 10 orridors. Eah orridor is profiled and analyzed relative 1 'Exludes gas used for pipeline fuel as well as lease (field) and plant proessing. Also does not inlude Alaska and Hawaii. Energy Information Administration, Natural Gas Annual 1996, DOE/EIA-0131(96) (Washington, 3 Unless otherwise speified, historial or general prodution and DC, September 1997), Table 1. onsumption data ited throughout this report are based on the publiation, 2, Annual Energy Outlook 1996,, Natural Gas Annual 1996, DOE/EIA- DOE/EIA-0383(96) (Washington, DC, January 1998). 0131(96) (Washington, DC, September 1997).

10 to its ombined pipeline apaity and usage levels, espeially as to its reeipt apability from supply areas and deliverability to market areas. The hapter also examines apaity expansions that have ourred sine 1990 along eah orridor and the potential impat of proposed new apaity. Chapter 4 disusses the last step in the transportation hain, that is, deliverability to the ultimate end user. Flow patterns into and out of eah market region are disussed, as well as the movement of natural gas between States in eah region. The profile of the ustomer base is addressed to provide some insight into the urrent operation of pipeline and storage failities in the market area. The potential impat of announed expansion projets is analyzed relative to urrent apaity levels and the regional demand profile. Chapter 5 examines how shippers reserve interstate pipeline apaity in the urrent transportation marketplae. It looks at how pipeline ompanies are handling the seondary market for short-term unused apaity that is plaed on the market by shippers eager to lower their overall transportation osts. It also analyzes the level of this (apaity release) trading and what urrent trends might mean for firm and interruptible ontrat (reservation) levels on pipelines in the future. The report also inludes four appendies that provide supporting data and additional detail on the methodology used to estimate apaity. For the most part, the time series data used in this report over the years 1990 through There are a few exeptions worth noting, however. Pipeline projets ompleted in 1997 are inluded in the analyses in hapters 3 and 4, although these projets were only in servie for a part of the year. Sine pipeline flow data for 1997 were not yet available, no attempt was made to integrate the 1997 projets into any disussion of pipeline utilization or speifi State-to-State apaity profiles. Another exeption is the energy onsumption data in Chapter 4 (and Appendix C, Table C1). As of Marh 1998, no omparative annual data for 1996 were available onerning total national energy onsumption by fuel type. While this limited the data time series to the period 1990 through 1995, the use of average annual (perent) hange in the aompanying profile analyses minimized the impat of the 1 year of missing data. It should also be noted that the analysis in Chapter 5 examines firm transportation ontrat data for the 1997 heating year (the 12 months ended Marh 31, 1997). Analyses onerning out-year projetions vary with the types of issues being addressed. Projetions of pipeline apaity additions through the year 2000 presented in the report are based upon atual proposals urrently under ative onsideration by the pipeline ompanies and regulatory authorities. Some of these projets may not survive the development proess. Projetions onerning prodution (Chapter 2) and future demand levels (Chapter 4), on the other hand, reflet estimates presented in EIA s Annual Energy Outlook 1998 With Projetions to 2020 as produed from the EIA s National Energy Modeling System (NEMS). Defining Deliverability Deliverability is defined for this report as the maximum volume (apaity) that an be reeived, delivered, or passed through a speifi point during a speified period, e.g., 1 day. Pipeline deliverability, or apaity, an be measured in different ways, resulting in slightly different meanings. For example: Systemwide peak-day apaity. Major interstate pipeline ompanies file an annual apaity report (18 CFR ) with the Federal Energy Regulatory Commission (FERC) that reports their daily system apaity based on a design estimate of how muh their system an deliver for urrent shippers on a systemwide peak day, otherwise known as the oinidental peak day 4 (Table 1). The derivation of this figure differs among pipeline ompanies. Estimates of apaity on grid type (regional) systems (see Pipeline Utilization setion) often are based upon the sum of system maximum deliverability when the system is in a balaned state (reeipts math deliveries). Systemwide apaity on trunkline systems usually represents the sum of apaity at all delivery points. Peak-day apaity of eah individual reeipt, delivery, or interonnetion point. This estimate represents the maximum amount of natural gas that an be delivered into or out of the system during a period based on an individual ustomer s peak needs, although no system is apable of reahing these maximums at all points on the same day. The sum of these apabilities is known as the nonoinidental peak-day apaity. It is alled nonoinidental beause the days on whih delivery points on a pipeline system experiene their peak flow may not oinide. Capaity at a speifi (strategi) point along the pipeline system, usually at a ompressor station or hub interonnetion (of several pipelines). Compressor A oinidental peak flow is a volume measured at a delivery, reeipt, or 4 interonnetion point during a speified period (usually a day) when the entire pipeline system operated at its maximum (throughput) for a given year. Thus the day for this measure oinides for all shippers.

11 Table 1. Forty Largest Interstate Pipeline Companies by Level of Deliverability, 1996 Systemwide Coinidental Number of Number of Number of Peak-Day Peak-Day 4 5 Type of Reeipt Delivery Interonnet Capaity System Flow 1 Company Name System Points Points Points (MMf/d) (MMf) Columbia Gas Transmission Co. Grid ,445 7,309 Transontinental Gas Pipeline Co. Trunk ,376 6,448 CNG Transmission Co. Grid ,275 6,899 Tennessee Gas Pipeline Co. Trunk ,981 6,887 ANR Pipeline Co. Trunk ,923 6,311 Texas Eastern Transmission Corp. Trunk ,761 5,414 Natural Gas Pipeline Co of Ameria Trunk ,208 5,957 El Paso Natural Gas Co. Trunk ,744 4,075 Northern Natural Gas Co. Grid/Trunk ,800 4,290 Koh Gateway Pipeline Co. Grid/Trunk 937 1, ,598 3,741 Northwest Pipeline Corp. Trunk/Grid ,300 2,907 Texas Gas Transmission Corp. Trunk ,950 3,621 Panhandle Eastern Pipeline Co. Trunk ,917 2,744 Noram Gas Transmission Co. Trunk/Grid ,811 2,335 Great Lakes Gas Transmission Co. Trunk ,712 3,767 PG&E Gas Transmission Co. - Northwest Trunk ,619 2,756 Transwestern Gas Pipeline Co. Trunk ,615 1,292 Southern Natural Gas Co. (SONAT) Grid/Trunk ,411 2,848 National Fuel Gas Supply Corp. Grid/Trunk ,222 2,159 Columbia Gulf Transmission Co. Trunk ,063 2,845 Colorado Interstate Gas Co Grid/Trunk ,000 2,162 Northern Border Pipeline Co. Trunk ,760 1,791 Trunkline Gas Co. Trunk ,987 1,896 Williams Natural Gas Co. Grid/Trunk , Mississippi River Gas Transmission Co. Trunk ,724 1,703 Algonquin Gas Transmission Co. Trunk/Grid ,645 1,513 Florida Gas Transmission Co. Trunk ,497 1,611 Questar Pipeline Co. Grid/Trunk ,380 1,167 Sabine Gas Pipeline Co. Trunk ,304 1,211 Equitrans In. Grid Iroquois Gas Pipeline Co. Trunk ,017 Midwestern Gas Transmission Co. Trunk Kern River Gas Transmission Co. Trunk East Tennessee Natural Gas Co. Grid/Trunk KN Interstate Gas Co. Grid/Trunk Wyoming Interstate Gas Co. Trunk Viking Gas Transmission Co. Trunk Williston Basin Interstate Pipeline Co. Grid/Trunk Trailblazer Pipeline Co. Trunk Mojave Pipeline Co. Trunk Total 103,502 1 "Trunk systems are long-distane trunklines that generally tie supply areas to market areas. Grid systems are usually a network of many interonnetion and delivery points that operate in and serve major market areas. Some systems are a ombination of the two. Where two are shown, the first represents the predominant system design. 2 Pipelines with zero reeipt and/or delivery points transfer volume via interonnetions with other interstate pipelines. 3 Represents a reeipt, delivery, or emergeny interonnet with one or more of the other pipeline ompanies listed in this table. 4 Some pipeline ompanies reported their system levels in deaterms per day (Dth/d) rather than in million ubi feet per day (MMf/d). In those instanes, a fator of was used for the onversion. 5 Total volume reported as delivered off the entire pipeline system on its peak-day during the heating year extending from April 1, 1996, through Marh 31, All volumes reported in Dth/d and onverted to MMf/d using a onversion fator. MMf/d = Million ubi feet per day. Soure: Federal Energy Regulatory Commission (FERC). Reeipt/Delivery/Interonnets: FERC 567 Capaity Report, System Flow Diagram. Systemwide Peak-Day Capaity: FERC Annual Capaity Report (18 CFR ). Peak-Day Flow: FERC Form 2, Annual Report of Major Natural Gas Companies.

12 stations an be viewed as hoke points along a system be expressed as a reservation on system apaity for the beause they are designed to move a limited amount of reeipt and delivery of a maximum daily quantity of gas at gas through their loation over a period of time. Capaity speifi points along the network. Under firm transportation measures for individual pipelines at a hub are dependent ontrats, the pipeline ompany agrees to reserve apaity on upon the apabilities of the hub itself and operational its system to provide a shipper, suh as a loal distribution aspets of other pipelines using the hub during a peak ompany (LDC), industrial user, or eletri utility, with up to period. a speified quantity on any given day. Pipeline ompanies must stand ready to provide servie up to the volume level This report primarily uses the speifi point measure of speified under firm ontrats even though their shippers may deliverability, based on an estimated design throughput not need or atually request transport of that gas. (However, apability of a pipeline as it rosses State borders. This design in ertain instanes, pipeline ompanies have the authority to apaity estimates the flow that ould be obtained along a impose restritions on the level of servie they are obligated pipeline segment on a sustained basis under a speifi set of to provide (see Box, Operational Flow Orders )). onditions and thus provides a measure of omparability aross all pipeline systems. LDCs are still the prinipal providers of supply to the ultimate end user, aounting for about 42 perent of the natural gas It should be emphasized that the apaity numbers derived for sold to end users in 1996 (down from 46 perent in 1993) and this report are merely reasonable estimates based upon 25 perent of the gas transported on their behalf (up from design or ontratual onditions. Atual apaity at a 20 perent in 1993). They typially ontrat with pipeline partiular point or system wide is rarely one stable figure. ompanies for firm transportation and storage servies to meet Weather onditions, ambient temperature, elevation, and the requirements of their high-priority ustomers and for 5 operational variables, suh as short-term line paking and interruptible servie to meet the needs of their lower priority line pressure shifts, an affet stated apaity levels. In some ustomers. However, in some States where open-aess ases, line paking an inrease operational apaity by as transportation and deregulation are being tested, LDCs are muh as 20 to 30 perent. Some of this inrease is refleted in slowly beoming merely deliverers for other sellers. In 1996, the differenes between system apaity and peak-day flows nonsales deliveries represented 37 perent (4.9 trillion ubi shown in Table 1. In a number of ases, the peak-day flow is feet) of total LDC deliveries, up from 30 perent in well above the reported overall system apaity. Consumers are generally lassified into four ategories: (1) The pipeline apaity estimates in this report are based residential, (2) ommerial, (3) industrial, and (4) eletri primarily upon ompressor station data in the Federal Energy utility. Residential and ommerial gas onsumers usually Regulatory Commission Format 567, System Flow have no other alternative for fuel exept through the LDCs Diagrams, filed annually by the major interstate pipeline and thus are onsidered high-priority users. In ontrast, many ompanies. (See Appendix C for a detailed disussion of how industrial users and eletri utilities do not require firm apaity levels were derived and refined.) Systemwide servie beause they often have the apability to swith to apaity levels, when used, are based upon data reported to other fuels. Some eletri utility and industrial onsumers FERC by the major interstate pipeline ompanies in their ontrat for servie on an interruptible basis. Under annual apaity reports that aompany Format 567 (18 CFR interruptible ontrats, deliveries are subjet to urtailments ) or onstruted from pipeline delivery data reported by the pipeline ompany or loal distribution ompany when on FERC Form 11, Natural Gas Pipeline Company Monthly neessary to meet the requirements for servie under firm 6 Statement. ontrats. Rates for interruptible servie are generally less expensive than for firm servie. Servie to interruptible shippers is extremely important to the pipeline ompanies in their efforts to maintain a high level of throughput. Shipper Requirements Ultimately, the shippers requirements determine the design apaity of pipeline system failities. Pipeline ompanies seek to obtain a mix of shippers and ontrat types in order to maximize system throughput. Firm servie requirements may 5 Line paking is temporary storage of pipeline gas through the use of inreased ompression. 6 The FERC Form 11 data used are only through The form was revised in 1996 and now is filed only on a quarterly basis. The demand for natural gas is quite diverse regionally. For example, in the northern regions of the ountry where a high proportion of residential and ommerial onsumers use natural gas for heating, deliveries under firm servie ontrats are highly seasonal beause of the extreme weather variation. Other more temperate regions, suh as the Southwest, may be very dependent on natural gas used in the generation of eletriity to meet summer ooling loads. The use of natural gas for industrial purposes also varies substantially from

13 Operational Flow Orders When FERC Order 636 was instituted in 1993 and open aess beame the norm, the Federal Energy Regulatory Commission reognized that pipeline operators needed a mehanism in plae that would still allow them to maintain the operational integrity of their system during periods of potential flux and when the system is under stress. Conditions suh as extreme weather, unsheduled downtime on ritial parts of the system, and extreme imbalane situations are some of the reasons pipeline ompanies ite as the need for suh short-term ontrol. Operational flow orders (OFOs) (also alled system emergeny orders or ritial period measures) are the mehanisms put in plae to permit this ontrol. In effet, these orders permit the pipeline operator during emergeny situations to restrain shipper ativities and to urtail servies that ould result in imbalanes and servie interruptions. For instane, OFOs allow the operator to redue or eliminate flow toleranes and require shippers to maintain a strit daily balane between reeipt and delivery volumes. The OFO also may restrit or eliminate suh servies as intraday nominations, the use of seondary reeipt and delivery points, firm storage withdrawals, and interruptible storage servies. As an enforement measure, pipeline ompanies an exat penalties for violations (pipeline ompanies do not bear any osts inurred as a result of servie restritions and they get to keep any penalty revenues). Despite their utility, OFOs are ontroversial. The diret onsequene of measures taken under OFOs is to lessen short-term trading and shipping flexibility on the part of ustomers. Some maintain that pipeline operators are given too muh disretion regarding what onstitutes an OFO situation and that operators have inentives for maintaining the OFO for longer than is needed. Critis also argue that the fat that the pipeline ompany an retain any penalty revenues and plae restritions on nonfirm servies and seondary reeipt/delivery points is a disinentive to shippers who want these lower-ost servies but are unwilling to risk possible interruption of their operational flows during peak periods. While operating ontingenies must be addressed and some form of pipeline system ontrol during stress periods and emergenies will ontinue to be required, the riteria for OFO implementation may be hanged as more experiene is gained with emergeny situations under open-aess onditions. For instane, it has been suggested that the restritions be imposed in a ratheted manner, implementing more severe restritions only if the lesser ones fail to alleviate the situation. Among the other possibilities: limit restritions only to those parts of the system that are under stress; give shippers more advane notie before issuing the OFO; remove any finanial inentives to pipeline ompanies under the OFO; and learly define within the pipeline ompany s tariff the onditions for imposing an OFO and what operational onditions onstitute an end to an OFO. region to region. Some appliations use natural gas for feedstoks and require a seure, dediated supply of natural gas. Other uses are for boiler fuel where the user typially has the apability to burn other fuels in the event that natural gas is not available or is less eonomi than the alternatives. Transmission System Design The prinipal requirement of the natural gas transmission system is that it be apable of meeting the peak-day demand of its shippers who have ontrats for firm servie. To meet this requirement, the prinipal failities developed by the natural gas industry are a ombination of transmission lines to bring the gas to the market areas and of underground storage and liquefied natural gas (LNG) failities loser to the market areas to meet surges in demand (Figure 1). The design of the transmission lines and integrated storage sites represents a balane of the most effiient and eonomial mix of delivery tehniques given the operational requirements faing pipeline ompanies. The mix varies widely depending on the number and types of shippers and aess to supplies, either from prodution areas or underground storage. Many pipeline systems are onfigured prinipally for the longdistane transmission of supplies from prodution regions to market areas and are haraterized as trunklines (Table 1). At the other extreme are the grid systems, whih generally operate in and serve major market areas. Many of the grid systems an be ategorized as regional distribution systems. For the most part, they reeive their supplies from major trunklines or diretly from loal prodution areas and transport gas to loal distribution ompanies and other onsumers in more than one State. Underground storage is an essential omponent of an effiient and reliable interstate natural gas transmission and

14 Figure 1. Generalized Shemati of Natural Gas Pipeline Transmission (Exess) Underground Storage LNG (peaking) Storage Market Area Storage Peak Periods Prodution Dry Gas Baseload Ultimate Consumer Offpeak Periods Liquids Proessing Plant (Extration) Note: Areas shown are not proportional to atual operational volumes or apaity. Soure:, Offie of Oil and Gas. distribution network. The size of the transmission line often depends in large part on the availability of storage. Rather than size a line to meet peak-day volumes, the line need satisfy only the differene between total shipper peak requirements and maximum withdrawal from storage as it enters the market area. In off-peak periods, the line must be able to provide shippers off-peak needs plus injetion to storage. In addition, some storage sites may require that system flow be reversible and that the main transmission line in the viinity be able to aommodate this apability. The resulting pipeline onfiguration, inluding storage, may result in a omparatively low usage level in the off-peak season and a muh higher, albeit shorter term, usage level during the peak-demand season. During the nonheating season, for instane, when shippers do not use all the apaity ontrated for, natural gas an be transported and injeted into storage at a fairly onstant rate. By the beginning of the heating season (November 1), inventory levels are generally at their annual peak. Working gas, that is, the portion of natural gas in storage sites 7 ordinarily available for withdrawal and delivery to markets, is then withdrawn during periods of peak demand. In addition, the pipeline ompany itself an avoid the need to expand transmission apaity from prodution areas by using existing, or establishing new, storage failities in market areas 7 In addition to working (top storage) gas, underground storage reservoirs also ontain base (ushion) gas and, in the ase of depleted oil and/or gas field reservoirs, native gas. Native gas is gas that remains after eonomi prodution eases and before onversion to use as a storage site. Native gas and base gas typially are not withdrawn from the storage faility, as these volumes are neessary to ensure suffiient pressure for the withdrawal of the working gas. where there is a strong seasonal variation to demand and where the system may be subjeted to some operational imbalanes. The daily deliverability from storage an also be fatored into the design needs of a new pipeline or the expansion needs of an existing one. Some underground storage failities are loated in prodution areas at the terminus of the pipeline orridor and, in ontrast to storage near loal markets, an be used to store gas that may not be eonomially marketable at 8 the time of prodution. These sites an be used by shippers to store short-term exess supplies that exeed their reserve apaity on the pipeline system and the reverse when supplies fall below reserved apaity. Thus, the pipeline is relieved of additional demands for apaity brought on by temporary swings in transportation demands. Often new systems are initially designed to handle volumes beyond the minimum requirement. A number of fators are involved in alulating how muh gas a pipeline an arry, the most important being the diameter of the pipe and the 9 pressure pushing the gas along the pipe. Beause of flow dynamis, doubling the diameter of the pipe will inrease the 8 For instane, natural gas produed in assoiation with oil prodution is a funtion of oil market deisions, whih may not oinide with natural gas demand or available pipeline apaity to transport the gas to end-use markets. Another example is the storage of gas from low-pressure wells, where the gas an be injeted during the off-peak season and delivered, at high pressure, to the mainline during the peak season. 9 Standard design odes require that all pipelines passing though populated areas have their maximum operating pressures redued for safety reasons. It beame ommon pratie to maintain nominal diameter but inrease wall thikness where a line had to be derated for its surroundings in order to keep the working pressure rating more onstant along the line.

15 apaity more than sixfold at approximately twie the ost. Inreasing the pipe wall thikness or strength of the pipe will enable the pipe to withstand a greater pressure. The pressure pushing the gas is usually provided by mehanial ompression. The design proess itself inludes the development of ost estimates for various possible ombinations of pipe size, ompression equipment, and interstation distanes to find the ombination that minimizes transportation ost given the desired flexibility and expandability goals. New trunklines are typially built with larger diameter pipe than needed initially, but only with the urrently required ompression apaity. Compression an then be added, either in existing or new, intermediate stations, to inrease apaity as growth in load ours. Pipeline Utilization Pipeline ompanies prefer to operate as lose to apaity as possible, thus maximizing revenue; however, the average annual utilization rate usually does not reah 100 perent even in ases of full utilization. Several fators ontribute to these lower rates, inluding the outages resulting from pipeline maintenane. During the summer months, when pipeline apaity demands are lowest, most pipeline ompanies shedule needed maintenane. As a result, some pipeline segments or ompressor failities may be plaed out of servie and transportation servie suspended temporarily, for a day, a week, or even as long as a month. Thus, average utilization rates below 100 perent do not neessarily imply that additional apaity is available. A pipeline ompany that serves primarily a seasonal market may have a relatively low average utilization rate even if there is no unreserved apaity on its system. Yet beause of the diffiulty in balaning unused ommitments for firm servie with interruptible servie and transportation for others, it may be unable to provide further interruptible servie to omplement the high level of deliveries required during the peak onsumption periods. Integration of storage apaity into the pipeline network design an inrease average-day utilization rates. Storage used for seasonal demand-swings effetively moves demand from one season of the year to another. Trunklines, whih are generally upstream of the market storage areas, an be designed for a more onstant load than the pipelines on the downstream side of the storage fields. Storage is usually integrated into or available to the system at the prodution and/or the market end as a means of balaning flow levels throughout the year. Therefore, trunklines serving markets with signifiant storage apaity have a muh greater potential for obtaining a high utilization rate beause the load moving on these pipelines an be levelized. Furthermore, to the extent these pipelines serve multiple markets, they an also ahieve higher utilization rates beause of load diversity aross the markets they serve. In fat, some trunkline systems, espeially those reahing high-demand markets, often exhibit peak daily utilization rates greater than 100 perent. For example, the Iroquois Pipeline system, whih transports Canadian gas to the U.S. Northeast, showed a peak-period usage rate above 100 perent in 1996, as did the Trailblazer Pipeline system out of the Roky Mountains area. Several fators ontribute 10 to this situation. First, some trunkline systems are apable of handling muh larger volumes than indiated by the operational design level ertifiated by FERC, whih is the level that is used as the denominator when alulating usage rates (based on an annual throughput volume divided by 365 days). Seond, as the line an handle more than the ertifiated apaity and shipper demand is high, maximum usage is made of the pipeline by its owners. In many instanes of high demand, pipeline ompanies also use line paking and/or seondary ompression to inrease throughput, whih was a tati used by both Iroquois and Trailblazer this past year. When average daily utilization rates exeed stated apaity, it is more appropriate to use the peak-day volume as the atual apaity, or apability, of the system. Utilization on the grid systems operating loser to the market areas and downstream of the storage fields is more likely to reflet the seasonal load profile of the market being served than utilization on upstream trunklines. The grid-type systems usually operate at lower average utilization levels than the trunklines, although during peak periods, usage levels are generally also at muh higher rates. Grid systems usually show a marked variation between high and low flow levels, refleting their seasonal servie and loal market harateristis. Storage servies are usually highly integrated into the grid network to meet varying loal market demands. Beause grid systems have numerous interonnetions within the network, their overall usage levels depend upon what happens in the various parts of the system. Pipeline segments that show a high degree of utilization are either serving a It should also be noted that in some instanes the sum of individual 10 transportation transations may exeed pipeline apaity even though physially the pipeline may be full. For example, suppose a segment from points A to D (with points B and C between A and D) has a apaity of 200 million ubi feet (MMf) per day. Suppose further that this segment handles a 100 MMf per day transation from A to B, a seond of 100 MMf per day from B to C, and a third of 100 MMf per day from C to D. The pipeline ompany will report transportation volumes of 300 MMf per day, even though its apaity is 200 MMf per day but is only 50 perent utilized on any one segment.

16 shipper (or group of shippers) with relatively onstant 11 review of the environmental aspets of the projets. These demand or have a signifiant interruptible servie market. requirements have resulted in a very time-onsuming, omplex, and sometimes ontroversial proess. The primary measure of pipeline utilization used in this analysis is an estimate of average-day natural gas throughput One a projet is approved and onstruted under a Setion relative to estimates of system apaity at State and regional 7() ertifiate, the osts of the failities are eligible for boundaries. Another measure used is systemwide pipeline inlusion in the pipeline ompany rate base (when the flow rates, whih highlight variations in monthly system 12 ompany files its next general rate ase). Other options are usage relative to an estimated system peak throughput level also available to pipeline ompanies for apaity expansion, (see Box, Pipeline Utilization Measures ). In some instanes, depending on the size of the projet and the amount of risk where data were available, pipeline peak-day utilization rates the ompany is willing to assume. These options inlude: are referened in this report. System peak-day usage rates, although only a refletion of peak system deliveries versus Blanket Certifiate. Blanket ertifiation an be used for estimated system apaity, ome the losest to showing how relatively small projets. A blanket ertifiate approves a well the design of the system mathes urrent shipper peak- series of similar ations in one authorization. For day needs. For example, when a pipeline shows a ompara- instane, onstrution of small additions to a pipeline may tively low average usage rate (based on annual or monthly be authorized by a blanket ertifiate, provided the total data) yet shows a usage rate approahing 100 perent on its ost does not exeed some threshold level and other peak day, it indiates that the system is still alled upon and eligibility riteria are met. Similarly, pipeline ompanies is apable of meeting its shipper s maximum daily needs. may be allowed to transport gas on a self-implementing Nevertheless, a large spread between average usage rates and basis (without prior FERC approval) for many different peak-day usage rates an indiate a need to find better ways shippers on the approval of a single blanket ertifiate. In to utilize off-peak unused apaity. reent years, FERC has been using blanket ertifiation more frequently to authorize and failitate both onstrution projets and transportation programs. Capaity Expansion Although pipeline systems have some flexibility in handling hanges in demand, sometimes system expansion and new pipeline routes are needed. There was substantial interest in expansion of the national pipeline network during the late 1980's and early 1990's and that interest ontinues today. Two of the largest proposals of the late 1980's to be implemented during the early 1990's were the Iroquois projet, built to bring Canadian natural gas into the Northeast, and the Kern River projet, whih now transports natural gas from supply soures in Wyoming to California. These new lines began servie in 1991 and 1992, respetively. A large number of other new systems and expansions are planned or under onstrution that will bring additional supplies from Canada, as well as from the Roky Mountains area and the Southwest, to the U.S. Midwest and Northeast regions. In most ases, interstate pipeline ompanies are required under Setion 7() of the Natural Gas At of 1938 to obtain a ertifiate of publi onveniene and neessity before onstruting pipeline failities. Besides review of operational aspets of the system, other legislation requires extensive Optional Certifiate (formerly known as Optional Expedited Certifiate). In 1985, under Order 436, FERC introdued optional ertifiates whereby onstrution ould be approved without assessment of its market need or ompetitive proposals. In return, the pipeline ompany agrees to bear the majority of the risk of the projet. Furthermore, the pipeline ompany may not derease the projeted volume of servies used to design rates nor shift osts to pre-existing shippers. Beause of the at risk fator, some optional ertifiate projets tend to be more adversely affeted by proedural delays sine hanges in market onditions that our in the meantime may neessitate a re-evaluation of the projet s feasibility and its potential suess. NGPA Setion 311. Setion 311 of the Natural Gas Poliy At (NGPA) of 1978 allows an interstate pipeline ompany to sell or transport gas on behalf of any 11 These laws inlude: the National Environmental Poliy At, National Historial Preservation At, Endangered Speies At, Toxi Substanes Control At, Clean Air At, Clean Water At, Coastal Zone Management At, Wild and Seni Rivers At, Wilderness At, and National Parks and Rereation At. 12 In some instanes, FERC may also issue a Setion 7() ertifiate subjet to at risk onditions. In suh ases, the pipeline ompanies are not guaranteed authority to inlude osts in the rate base, and risks borne by the ompanies are not redued. Under an at risk ertifiate, a pipeline ompany's risk is minimized only where it has fully ontrated the apaity of a new line.

17 Pipeline Utilization Measures At State Borders The State-to-State measure of pipeline utilization used in this analysis is based on estimates of average-day pipeline throughput relative to estimates of system apaity at State boundaries. Average-day throughputs were omputed by dividing annual Stateto-State flows in 1990 (reported by pipeline ompanies) by 365 days and those in 1996 by 366 days. Average-day utilization for the 2 years were then derived by dividing the average-day flow by the estimated apaity level. This measure provided the basis for the analysis pertaining to usage of speifi portions of a pipeline system and additionally some insight into the type of servie provided in the area. But, beause it uses averaged annual throughput volumes, the measure implies nothing about the availability of apaity during peak periods, exept to the extent that the average daily utilization approahes, or exeeds, 100 perent. (Servie levels on a pipeline system often vary from month to month, day to day, and even hourly.) As the omputed utilization rate approahes 100 perent, it indiates only that the volume of gas moving through a speifi geographi area on an average day during the year approximated estimated apaity. When this does our, however, it is likely that the speifi system loation experienes some onstraints during peak periods. A system that fully utilizes available apaity for short periods and not on a sustained basis throughout the year will show a lower utilization rate based on a daily averaging of annual throughput. Systemwide In order to evaluate operational and utilization levels of the various pipeline systems during the year, several flow-rate derivations were omputed. These rates are based on a omparison of 1995 monthly throughput (the latest available monthly data) on the entire pipeline system with the largest throughput (sales, transportation, and interompany transfers) that ourred in any month over a 15-year period ( ). They were developed to show the degree of differene that ours on different types of systems over the year as seasons and demand hange. In these omputations, the highest monthly throughput during the 15-year period is used as the proxy for the systemwide apaity of the pipeline. (This method has its limitations, inluding the fat that aounting of throughput an vary by pipeline ompany, leading to the reporting of exess throughput levels.) For 1995, (1) average-month throughput, (2) high-month throughput, and (3) low-month throughput were eah divided by the 15-year high-month throughput to derive three flow-rate perentages. In addition, a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September divided by 153 days, was also omputed. (April and Otober are onsidered to be months that shoulder the heating season of November through Marh.) Another systemwide usage rate was also omputed based upon an annual system (deliverability) apaity level reported to the Federal Energy Regulatory Commission (FERC) by the major pipeline ompanies and the system s yearly peak 1-day volume. This figure provided a snapshot of the system s maximum use level ontaining a minimum skew aused by downtime and other fators. An analysis of the peak-day, high month, low month, average monthly, and average summer (off-peak) throughput rates provides some understanding of the load variability on a pipeline system throughout the year. For instane, systems with a high-month rate of 100 perent in 1995 had a reord monthly throughput level in If these same systems also exhibited high average utilization rates at State border rossings, they may be onstrained in their abilities to serve additional shippers without apaity expansion. In ontrast, systems having a relatively low peak-month throughput but high average utilization levels at speifi points along the network probably are experiening more loalized apaity onstraints. Comparison of the systemwide average-month flow rates with utilization rates at State border rossings an provide insight into how representative the individual utilization rates are of the whole system. For example, if utilization rates are very high at State border rossings but the systemwide average-month rate is signifiantly lower, then there are likely to be elements of the system, probably wholly ontained within a region or State, where utilization is low. Conversely, if utilization rates at State borders are very low but the systemwide average-month rate is signifiantly higher, then there are likely to be elements of the system where utilization is quite high. These areas are likely to be near supply regions where interstate pipelines interonnet and transfer large volumes of gas from one system to another.

18 new pipeline projets at various stages of development in the United States, Canada, and Mexio. If all U.S. projets were ompleted, the amount of new apaity would add more than 29 billion ubi feet of daily deliverability on the national network. The most extensive development is foused on expanding the deliverability of Canadian gas to the U.S. Midwest and Northeast and to Canadian markets. The seond- largest fous is on improving aess to the inreasing deep- water prodution in the Gulf of Mexio. Next are those projets whose objetive it is to inrease the flow of lowerinrease flows of Western Canadian gas to the Midwest ost supplies loated in the Central United States to markets loated primarily in the Midwest. Currently, the apability to do so is limited. The latter series of expansions will be ompeting, to some degree, with the projets slated to marketplae. The potential impat of proposed apaity expansions is disussed in subsequent hapters. intrastate pipeline or loal distribution ompany. FERC has exempted the onstrution of failities used solely for Setion 311 transportation from ertifiate requirements. Constrution is subjet to environmental onditions and a 30-day notie to FERC, whih requires only information on the delivery point of gas from the interstate pipeline, the total and daily volumes expeted to be delivered, and the rate to be harged for transportation or sale. Planned expansions of the urrent pipeline system are proposed under eah of these options and are detailed in Appendix B. The traditional Setion 7() appliation is still the most widely used. As of Marh 1998, the was traking more than 100 proposed pipeline expansions and

19 2. Aess to Supplies and Prodution Areas Natural gas prodution patterns in the lower 48 States have 1990s, growing as a major soure of deliverability in the hanged in reent years as new fields have been brought on lower 48 States. line and older gas-produing areas have delined in importane. For example, the eighth largest gas field in the Alaska is not inluded as a supply area in this study beause United States in 1996 in terms of output, Bob West in its natural gas prodution is not destined for U.S. markets in southern Texas, was disovered only in 1990 and as late as the lower 48 for some time to ome and therefore does not 1993 did not even figure among the top 30 produers. Also, diretly affet U.S. gas deliverability within the time frame of new tehnology has rejuvenated older fields and allowed the analysis. prodution from fields previously thought uneonomi. The shifts in regional prodution will affet existing pipeline routes, reduing flows along some, while inreasing flows along others. Some regional prodution inreases from new gas fields in the Roky Mountain area and New Mexio will require additional apaity to transport the gas to markets. The Gulf Coast region has seen a substantial inrease in prodution over the past several years and, although traditionally served by an extensive pipeline network, will probably require the addition of new apaity. Meanwhile, prodution in the Anadarko and Arkoma Basins delined during the first half of the 1990s. This hapter disusses U.S. natural gas deliverability at the wellhead through 2000 and the apability of the pipeline network to reeive and export that gas through the national network grid. The analysis fouses on eight produing areas that roughly orrespond to major geologi basins in the lower 48 States (Figure 2), as well as imports from Canada. Relatively new produing regions (in terms of average field age) overed in this hapter inlude the offshore Gulf of Mexio; major fields in the Roky Mountain States of Utah, Colorado, and Wyoming; and the San Juan Basin of New Mexio. Older produing regions examined inlude the Permian Basin; the onshore Gulf Coast of Texas and Louisiana; the Anadarko and Arkoma basins in Oklahoma, Kansas, and Arkansas; the fields of East Texas; and the 13 Appalahian Basin. Although a relatively minor gas produer, the Appalahian Basin region is notable beause of its proximity to major markets in the Northeast. Canada has sharply inreased gas exports to the United States during the U.S. Natural Gas Supplies by Region, Total natural gas prodution in the lower 48 States has shown an upward trend during the 1990s, rising 5 perent from an average 47.7 billion ubi feet (Bf) per day (17.4 trillion ubi feet (Tf) on an annual basis) in 1990 to 50.1 Bf per day (18.4 Tf per year) in 1996 (Table 2), its highest level sine the early 1980s. Higher gas demand and stable pries are projeted to raise prodution in the lower 48 to about 54 Bf per day (19.8 Tf per year) in The 1.9-perent average annual growth rate foreast for the period 1996 through 2000 is more than double the prodution growth rates of the first half of the 1990s. 14 Lower 48 gas reserves inreased to 156 Tf in 1996, marking the third onseutive year of higher reserve levels although still slightly below the 1990 level of 160 Tf. This reent trend is expeted to ontinue. Various fators, suh as improved well ompletions, advaned stimulation tehnology, and improved seismi tehnology, have allowed produers to maximize gas output from existing fields, resulting in a deline in the ratio of reserves to prodution sine The near-term supply outlook for natural gas shows expanded prodution through 2000, refleting the reent prodution trends as well as the substantial volume of remaining 15 resoures. One reent study estimated remaining reoverable gas resoures at 929 Tf as of Deember 31, 1996, suggesting 14 Unless otherwise noted, all foreasts are derived from data in the Energy Information Administration (EIA) publiation Annual Energy Outlook 1998 With Projetions to 2020, DOE/EIA-0383(98) (Washington, DC, Deember 1997). Historial data for the lower 48 States are from EIA s Natural Gas Annual 1996, DOE/EIA-0131(96) (Washington, DC, September 1997), and earlier editions of this report. The lower 48 totals are disaggregated to regional 13 The regional data were aggregated from data by State and sub-state estimates, based on relative dry gas prodution values as reported in the EIA areas. The lak of strit orrespondene between the basins and these data report U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996, means that portions of basins may be exluded, or other lesser basins may be DOE/EIA-0216(96) (Washington, DC, Deember 1997), and earlier editions. 15 inluded in the regional estimates. For expository purposes, the regions, in, Annual Energy Outlook 1998, some ases, are treated as equivalent to the major basins within the regions. (Washington, DC, Deember 1997).

20 Figure 2. Major Natural Gas Produing Basins and Transportation Routes to Market Areas Western Canada Sedimentary Basin Williston Basin Green River Basin Powder River Basin Denver- Julesberg Basin Illinois Basin Mihigan Basin Uinta/Pieane Basin Saramento Basin San Joaquin Basin San Juan Basin Permian Basin Anadarko/ Arkoma Appalahian Basin Blak Warrior Basin East Texas/ North Louisiana Basins Capaity (Million Cubi Feet per Day) Gulf Coast Basin South Texas Basin 15,000 12,000 9,000 6,000 3,000 0 Correspondene to Major Natural Gas Produing Regions Produing Region State or Substate Regions Basins Contained Whole or in Part Gulf Coast South Louisiana (onshore) Gulf Coast and South Texas Basins Texas RRC Distrits 1, 2, 3, 4 Anadarko/Arkoma Arkansas Anadarko/Arkoma Basin Kansas Oklahoma Texas RRC Distrit 10 Permian Basin New Mexio, East Permian Basin Texas RRC Distrits 7B, 7C, 8, 8A, 9 Rokies Colorado Uinta/Pieane, Julesberg, Powder River, and Utah Green River Basins Wyoming East Texas North Louisiana East Texas/North Louisiana Basins Texas RRC Distrits 5, 6 San Juan Basin New Mexio, West San Juan Basin Appalahian New York Appalahian Basin Ohio Pennsylvania Virginia West Virginia Other Onshore Alabama, California (onshore), Florida, Kentuky, Mihigan, Williston, Saramento, San Joaquin, Illinois, Mississippi, Arizona, Illinois, Indiana, Maryland, Missouri, Mihigan, and Blak Warrior Basins Montana, Nebraska, Nevada, North Dakota, Oregon, South Dakota, and Tennessee Offshore Federal waters of the Gulf of Mexio, and State waters of California, Alabama, Louisiana, and Texas Soure:, EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember 1997.

21 Table 2. Natural Gas Prodution and Supplies in the Lower 48 States, by Region, Annual Gas Supplies Daily Gas Supplies Change in Gas Supplies Share of Total Supplies (billion ubi feet per year) (billion ubi feet per day) (perent inrease/derease) (perent) Region (foreast) (foreast) (foreast) (foreast) Lower 48 Prodution Gulf Coast 3,130 3,340 3, Anadarko/Arkoma 3,339 2,929 2, Permian Basin 1,663 1,621 1, Rokies 911 1,497 1, East Texas 1,109 1,153 1, San Juan Basin , Appalahian Basin Other Onshore , Total Onshore 12,003 12,859 13, Offshore 5,425 5,491 5, Total Lower 48 17,428 18,350 19, Lower 48 Imports From Canada 1,448 2,883 3, Total Lower 48 1,532 2,937 4, Total Lower 48 Supplies 18,960 21,287 23, Soures: Data: (EIA), Natural Gas Annual 1996 (September 1997) and earlier editions. Prodution volumes by regions were derived based on relative dry gas prodution values published in U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 (Deember 1997) and earlier editions Foreasts: EIA, Annual Energy Outlook 1998 (AEO) (Deember 1997). When regions differed between the Natural Gas Annual and the AEO, regional prodution volumes were projeted for 2000 by applying the growth fator for the AEO region between 1996 and adequate domesti gas supplies through the near-term inreased demand for U.S. gas deliverability through the year 16 perspetive of the present analysis Of the 7.1 Bf per day (2.6 Tf) in additional U.S. gas supplies antiipated between 1996 through 2000, imports While higher gas prodution in the lower 48 States from Canada are likely to represent about two-fifths of supply ontributed to inreased U.S. gas supplies between 1990 and growth. Key domesti regions ontributing to the supply rise 1996, the soure of the largest portion of the inrease was are the offshore and Permian Basin regions with 15 and imports from Canada. Benefiting from strong U.S. demand 10 perent of the total inrease, respetively (Table 2). and a more open trade environment, Canadian gas exports to the United States nearly doubled between 1990 and 1996 and In 1996, the United States had nearly 302,000 produing gas aounted for about two-fifths of the inrease in U.S. gas 17 wells and gas-ondensate wells, as well as a very large supplies during this period. By 2000, imports of natural gas number of oil wells, yielding approximately 50 Bf of natural from Canada are projeted to aount for 16 perent of U.S. gas per day (18.4 Tf per year). The largest gas-produing gas supplies, more than double their 1990 share. region in the lower 48 States is the offshore region, followed by the onshore Gulf Coast, the Anadarko/Arkoma Basins, the The onentration of inreased gas supplies through 2000 in Permian Basin, and the Rokies. Together, these five regions a small number of areas Canada, the Roky Mountain area, aounted for 81 perent of total U.S. dry gas prodution in the Permian Basin, the San Juan Basin of New Mexio, and Eighty-six perent of U.S. onsumption is met by the offshore/onshore Gulf raises onerns about the ability domesti produers, while the remainder is imported mostly of the pipeline system and other infrastruture to meet from Canada. The following setions highlight the ontribution of eah major supply region to gas supplies and deliverability in the lower 48 States. 16 Remaining reoverable gas resoures are those volumes produible with urrent reovery tehnology and effiieny but without referene to eonomi viability. The estimate of 929 trillion ubi feet of remaining reoverable gas resoures is published in the report Potential Supply of Natural Gas in the 17 United States, Potential Gas Ageny, Colorado Shool of Mines (Marh, Natural Gas Annual 1996, 1997). DOE/EIA-0137 (Washington, DC, September 1997).

22 Offshore Gulf of Mexio The top gas-produing region in the lower 48 States is the offshore region, where prodution flows almost exlusively from the Offshore Gulf of Mexio. The Gulf aounted for almost 30 perent of natural gas prodution (Figure 3) and 18 more than one-fifth of proved reserves (Table 3) in the lower 48 in The reent rebound in offshore exploration and development ativity is likely to make the offshore region an important soure of inreased gas supplies during the late 1990s. Reent hanges in the soures of gas prodution in the Gulf in favor of assoiated gas and deep water gas have major impliations for future gas deliverability from this region and its impat on regional markets. Major plays in the Gulf of Mexio are found in the Flexure Trend, the Norphlet Trend, the Destin Dome, subsalt, and deep water fields. The Flexure Trend extends from Mobile Bay to Mexio and inludes fields in waters deeper than 600 feet; estimated produtive apaity in the Flexure Trend 19 was about 1.2 Tf in The Norphlet Trend is an extension of the Flexure Trend strething from Alabama to Florida ontaining fields at 600 to 2,000 feet of depth. Prodution in the Norphlet Trend was about 1 Tf in The Destin Dome, a part of the Norphlet Trend loated off the oast of the Florida Panhandle, is estimated to ontain 3 Tf of potential reserves. However, signifiant prodution here is not likely to begin until around 2000 and will therefore have minimal impat on U.S. gas deliverability in the near term. The ollapse of oil and gas pries in the mid 1980s aused a redution in overall exploration and development ativities in the Gulf that ontinued into the early 1990s. As the average U.S. wellhead prie fell by more than two-fifths in real terms 20 (1996 dollars) between 1985 and the early 1990s, offshore gas prodution was hit harder than onshore prodution beause of the rapid depletion of known deposits in shallow waters and higher inreased risks and osts assoiated with exploration and development of gas in deep water. Between 1990 and 1992, offshore gas prodution delined by 8 perent beause of the lak of reserves replaement. Total offshore reserves shrank 10 perent between 1990 and more than 13.0 perent between 1992 and 1996 to a level of 15.0 Bf per day (5.5 Tf per year). A 12-perent inrease in average gas wellhead pries over the average from 1990 through 1992 (in onstant 1996 dollars), oupled with a onethird deline in finding osts (also in 1996 dollars), ontributed to a dramati improvement in the profitability of 21 offshore gas prodution. Aording to one soure, offshore gas prodution by was profitable at average wellhead pries of only $1.75 per thousand ubi feet, down from a profitability threshold estimated at $2.50 per thousand ubi feet (in urrent dollars) in With 1996 U.S. wellhead pries averaging $2.17 per thousand ubi feet, offshore gas prodution had beome profitable after a high degree of unprofitability during the late 1980s and early 1990s. The very high exploration and development (E&D) expenditures assoiated with offshore projets, more than $1 billion in some ases, are delining generally as ompanies gain experiene with more hallenging deep water and subsalt projets. Both projet time horizons and platform osts are shrinking dramatially. For example, the apital portion of daily prodution osts for Shell s Ursa tension leg platform (TLP), due to begin prodution in 1999, is projeted to be slightly more than half that of Auger, Shell s first TLP 22 installed in Offshore projets partially ompensate for higher upfront expenditures with faster reovery of reserves through higher flow rates. The faster depletion of offshore wells requires more ontinuous exploration ativity to maintain prodution levels. The Outer Continental Shelf 23 (OCS) Deep Water Royalty Relief At (DWRRA), signed in November 1995, has also improved the eonomis of offshore prodution. The DWRRA provides for a waiver of royalty payments for prodution from new leases and ertain other deep water leases. 24 Overall, offshore gas prodution is projeted to grow 7 perent from 15.0 Bf per day (5.5 Tf per year) in 1996 to 16.1 Bf per day (5.9 Tf per year) in A key soure of expanded prodution is likely to be assoiated-dissolved (AD) gas from rude oil prodution (aounting for one-fourth of the inremental prodution), although expanded output of The large fields in the deep waters, ombined with ostutting new tehnologies, have greatly improved the eonomis of offshore gas prodution, raising offshore output 21 James Dodson and Leonard LeBlan, U.S. Gulf Rebound to Continue in 1995, Offshore (January 1995), p Deepwater, subsalt projets open new era for Gulf of Mexio ations, Oil and Gas Journal (January 20, 1997), p The law provides royalty relief to oil and gas fields in the Central and Western Gulf of Mexio that would not be eonomi to produe without 18 Proved reserves of natural gas are the estimated quantities whih analysis royalty relief. In partiular, fields that did not produe prior to November 28, of geologial and engineering data demonstrate with reasonable ertainty to 1995, and meet Minerals Management Servie (MMS) eonomi be reoverable in future years from known reservoirs under existing eonomi determinations may reeive royalty suspension volumes of at least 17.5 million and operating onditions. barrels of oil equivalent (BOE) in 200 to 400 meters of water, 52.5 million 19 WEFA, Natural Gas Outlook (Spring/Summer 1997), p BOE in 400 to 800 meters of water, and 87.5 million BOE in more than , U.S. Crude Oil, Natural Gas, and meters of water. 24 Natural Gas Liquids Reserves, Annual Report 1996, DOE/EIA-0216(96) Deepwater royalty relief produt of 3 ½ year U.S. politial effort, Oil (Washington, DC, Deember 1997), p. 10. and Gas Journal (April 1, 1996), pp

23 Figure 3. Lower 48 Natural Gas Prodution by Region, 1996 (Share of Total in Perent) Offshore (29.9%) Gulf Coast (18.2%) Anadarko/Arkoma (16.0%) Appalahian Other (4.5%) San Juan Basin (2.7%) (5.4%) Rokies (8.2%) Permian (8.8%) East Texas (6.3%) Total lower 48 prodution is 18.4 trillion ubi feet Soure:. Total 1996 Prodution: Natural Gas Annual 1996 (September 1997). Shares by Region: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 (Deember 1997). Table 3. Lower 48 Dry Natural Gas Proved Reserves and Reserves-to-Prodution Ratio, Proved Reserves Proved Reserves-to- (billion ubi feet) Prodution Ratio Region Gulf Coast 21,325 19,186 20, Anadarko/Arkoma 31,986 28,008 26, Permian Basin 15,718 13,534 14, Rokies 16,009 21,002 21, East Texas 10,216 10,376 11, San Juan Basin 14,004 14,624 13, Appalahian Basin 5,633 7,068 7, Other Onshore 9,584 8,027 8, Total Onshore 124, , , Offshore 35,571 33,824 33, Total Lower , , , Soure:, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 (Deember 1997).

24 deep water and subsalt gas also ontribute to prodution 27 startups expeted from 1997 through Ativity in the gains. deep waters of the Gulf of Mexio is expeted to remain strong as leasing ativity has responded to the royalty relief A more than one-third inrease in Gulf oil prodution sine at inentives. The number of bloks reeiving bids in the 1990 has led to higher output of AD gas, whih reahed sales sine the DWRRA was signed in November 1995 has 2.2 Bf per day (0.8 Tf), or 15 perent of total offshore gas risen substantially, with bloks in at least 800 meters prodution in Based on Energy Information numbering seven times the earlier ount (Table 4). Some of Administration (EIA) projetions of Gulf oil output through the deep water apaity oming on stream during the 1990s , AD gas will rise by another 0.25 Bf per day. The is replaing depleted deposits in shallower water. Deep water onsiderable future potential of AD gas is demonstrated by its gas prodution will ontribute to a net inrease in offshore large share of total offshore reserves, whih grew from less prodution during the latter half of the deade. than 20 perent in 1990 to 22.4 perent in Advanes in 3-D seismi interpretation and drilling through The growing influene of AD gas in the Gulf has provided thik setions of salt have made it possible to develop produers with some logistial hallenges and has possible resoures under sheets of salt that are believed to extend impliations for regional gas pries. Beause natural gas is under more than half of the Gulf of Mexio. In 1993, the first onsumed in aordane with seasonal market demand, the subsalt find to be ommerially developed, Mahogany, was fairly steady reovery shedule of AD gas from oil projets disovered, followed by seven more in 1994 and Even results in some gas being produed during periods of minimal though some initial suesses generated onsiderable interest demand. Suh an inelasti prodution shedule, harateristi in the estimated 15 trillion ubi feet or more of undisovered of AD gas, ould depress gas pries in the Gulf region during subsalt reoverable gas resoures, signifiant exploratory periods of minimal demand. risks remain and subsalt gas supplies are not expeted to be as signifiant in the near term as deep water gas. Less than 1 Bf Expanding prodution of AD gas in the Gulf of Mexio has per day of total additional prodution apaity is likely from therefore led to inreased use of storage along the Gulf Coast, new subsalt gas through the year In the longer term, so that produers an better math supplies to seasonal whih is beyond the sope of this report, subsalt gas demand. The antiipated inrease in AD gas prodution prodution ould have greater impat on offshore gas through 2000 is being aompanied by underground storage deliverability. expansions under development in Texas and Louisiana with 26 a ombined daily deliverability of 2 Bf per day. The steady movement of gas prodution into deeper, more Underground storage apaity is also being expanded near remote environments further offshore raises several major market areas in the Northeast and Midwest, where up hallenges related to delivery of gas from the field. They to 1.5 Bf per day in daily deliverability ould be added in inlude building the offshore pipeline network to bring the eah region by However, most likely not all planned new deep water gas ashore and expanding existing onshore apaity additions will be realized. pipeline apaity to aommodate the additional gas (see Appendix B, Natural Gas Pipeline and System Expansions, Other offshore prodution trends affeting gas deliverability "). inlude a movement to the deeper offshore and an emerging interest in subsalt deposits. While wells in water deeper than 1,000 feet (roughly 305 meters) have been produing gas in the Gulf sine the late 1970s, their role in offshore gas prodution was minimal until reent tehnologial advanes, suh as improved 3-D seismi surveys and floating prodution systems (see Box, Tehnologial Improvements ), allowed for the disovery and development of several large deep water deposits. By 1996, 20 new deep water prospets began produing, with a similar number of Onshore (Texas and Louisiana) Gulf Coast The Gulf Coast region, ontaining the oastal East and Southeast Texas (Railroad Commission Distrits 1, 2, 3, and 4), and Southern Louisiana, produed more gas than any other onshore region in the United States in 1996 after trailing the Anadarko and Arkoma Basins in the early 1990s. Gas prodution grew by roughly 6 perent between 1990 and 1996 and at 9.1 Bf per day (3.3 Tf per year) aounted for nearly 25, Annual Energy Outlook 1998 With Projetions to 2020, DOE/EIA-0383(98) (Washington, DC, Deember 1997) See, U.S. Underground Storage of Chris C. Oynes, Regional Diretor, Gulf of Mexio Region, Minerals Natural Gas in 1997: Existing and Proposed, Natural Gas Monthly, Management Servie, presentation at the OCS Workshop, Amerian DOE/EIA-0130(97/09 (Washington, DC, September 1997), pp xxi-xli. Assoiation of Professional Landsmen (Houston, TX, January 22, 1998).

25 Table 4. Central and Western Gulf of Mexio Lease Sales Before and After the Royalty Relief At Blok Water Depth Number of Bloks Reeiving Bids (meters) ,138 All Depths ,541 1,836 Note: The Outer Continental Shelf Deep Water Royalty Relief At was signed in November Soure: Derived from a speeh by Chris C. Oynes, Regional Diretor, Gulf of Mexio Region, Mineral Management Servie, to the OCS Workshop, Amerian Assoiation of Professional Landsmen (Houston, TX, January 22, 1998). 16 perent of U.S. gas supplies in the latter year. The two deliverability during January, the peak of the heating season largest fields in the region, Giddings and Bob West, are (November 1 through Marh 31), delined from 23 perent of loated in southern Texas. They produed a daily average of total deliverability in 1990 to an estimated 14 perent in and 0.3 Bf of wet gas, respetively, in 1996 (Table 5). (Table 6). Most of the onshore Gulf Coast s prodution is from nonassoiated gas, with AD gas aounting for only about one-tenth of regional gas prodution and reserves. Anadarko and Arkoma Basins A high degree of exploration ativity, enhaned by the use of horizontal and multilateral drilling, is yielding impressive results, partiularly around the Austin Chalk Trend. In Marh 1997, one well set an onshore U.S. horizontal well reord, flowing an average of 84 million ubi feet per day, whih was exeeded by another with an average flow of 100 million ubi feet per day in April Tehnology has also been employed in the onshore Gulf region to expand flow at produing fields, with a major developer of the Wilox/Lobo Trend ahieving a 75-perent suess rate in 1994 using 3-D seismi tehnology and improved fraturing fluids. Proved reserves in the onshore Gulf Coast region delined between 1990 and 1996 to the equivalent of 6 years worth of prodution, the lowest reserves-to-prodution ratio among major onshore gas-produing regions (Table 3). Reserves delined by more than 15 perent between 1990 and 1993 but have sine partially reovered to 20.1 Tf in 1996 as inreased exploration ativity from 1994 through 1996 found inreased gas at existing fields and some new finds. The new Texas finds in the Austin Chalk Trend, along with the potential for additional finds in the Louisiana portion of this trend, suggest further near-term growth potential for onshore Gulf Coast gas output. Between 1996 and 2000, gas prodution in the onshore Gulf Coast region is foreast to rise almost 3 perent to 9.4 Bf per day (3.4 Tf per year). Estimates of produtive apaity show that surplus wellhead Wet gas refers to produed natural gas that ontains liquid hydroarbons 28 that are removed at a natural gas plant. Dry gas is the gas remaining after liquids removal. The Anadarko/Arkoma region omprises Oklahoma, Kansas, Arkansas, and the Texas Panhandle area (Railroad Commission Distrit 10). It was the largest onshore gasproduing region in 1990, when prodution averaged 9.1 Bf per day (3.3 Tf per year) (Table 2). However, a sharp prodution deline in Oklahoma redued the region s gas prodution by more than 12 perent between 1990 and 1996 to a level of 8.0 Bf per day (2.9 Tf per year). A major fator in delining regional gas output was a nearly 30-perent ontration of produtive apaity between 1990 and By the mid-1990s, Anadarko/Arkoma had fallen to seond plae behind the Gulf Coast among onshore regions in terms of gas output volumes. It does remain the top onshore region in terms of proved reserves, despite a 17-perent drop in Anadarko/Arkoma proved reserves, from 32.0 Tf in 1990 to 26.6 Tf in 1996 (Table 3). The largest gas field in Anadarko/Arkoma is the giant Hugoton gas field in Kansas, whih dates from 1922 (Table 5). Despite its age, Hugoton was the seond largest U.S. gas field ranked by annual prodution in 1996 (1.5 Bf per day of wet gas) and is the largest U.S. field in terms of umulative prodution (about 22 Tf). Hugoton, whose prodution omes from low permeability sandy arbonate reservoir roks, oupies muh of the western half of Kansas and extends south into Oklahoma and the Texas Panhandle. Hugoton s gas output has been raised in reent years through the pratie of more intensive drilling in existing fields and through some new finds, inluding those along the Eubank hannel. This helped to offset signifiant delines in prodution at other Anadarko/Arkoma fields, partiularly in

26 Table 5. Top 10 Fields in the Lower 48 States Ranked by Natural Gas Prodution, 1996 (Billion Cubi Feet) Loation 1996 Share of Average 1996 Lower 48 Year of Daily Annual Prodution Rank Field Name State Produing Area Disovery Prodution Prodution (perent) 1 Basin NM San Juan Basin Hugoton Gas Area KS/OK/TX Anadarko/Arkoma Blano NM/CO San Juan Basin Giddings TX Onshore Gulf Coast Carthage TX East Texas Mobile Bay AL Offshore Gulf of Mexio Panhandle West TX Anadarko/Arkoma Bob West TX Onshore Gulf Coast Panoma Gas Area KS Anadarko/Arkoma Green Canyon Blk Fed. Offshore - Gulf of Mexio Total , Note: Gas is wet after lease separation. Soure:, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 (Deember 1997). Table 6. U.S. Natural Gas Produtive Capaity Utilization and Surplus Deliverability by Region, 1990, 1995, and 1996 Produtive Capaity Utilization (perent as of January) Surplus Deliverability (perent as of January) Region (estimate) (estimate) Gulf Coast Anadarko/Arkoma Permian Basin Rokies East Texas San Juan Basin Offshore Total Lower Note: Utilization fators for the Gulf Coast, Permian Basin, and East Texas regions are average fators for the relevant States weighted by the relative dry gas prodution volumes in the region. Soure:, Natural Gas Produtive Capaity for the Lower 48 States (Deember 1996). Oklahoma. In Otober 1997, Mobil and Anadarko Petroleum Corp. announed that they would jointly exploit deeper horizons in Hugoton, providing further indiation of future day (3.0 Tf per year) through 2000 (Table 2). potential. Two other Anadarko/Arkoma gas fields rank among the top 10 in the lower 48. Panhandle West in Texas produed a daily average of 0.36 Bf and the Panoma gas area in Kansas produed another 0.31 Bf daily on average in Contrating produtive apaity redued Anadarko/Arkoma s surplus deliverability from 28 perent in January 1990 to about 11 perent in January 1996 (Table 6). Output gains from infill drilling and some new finds at Hugoton, ombined with a stabilization of produtive apaity, should keep Anadarko/Arkoma s gas prodution level at about 8.1 Bf per Permian Basin The Permian Basin region spans from eastern New Mexio to western Texas (Railroad Commission Distrits 7B, 7C, 8, 8A, and 9). Gas prodution delined between 1990 and 1996, from 4.6 to 4.4 Bf per day (1.7 to 1.6 Tf per year), while proved reserves delined by about one-tenth to 14.1 Tf in

27 1996 (Table 3). The top five fields Gomez, Spraberry Trend A growing portion of Rokies natural gas prodution during Area, Pukett, Sugg Ranh, and Keystone aount for about the early 1990s ame from oalbed methane (Figure 4), one-quarter of total Permian Basin gas prodution and one- spurred by a Federal tax redit for natural gas produed from third of the region s proved reserves. AD gas aounts for oal seam wells with initial drilling prior to January 1, about two-fifths of gas prodution and reserves in the Permian This tax redit extends up to 10 years for any produing well Basin and is almost as large in absolute terms (about 2 Bf per so it will affet prodution on at least some portion of oalbed day) as offshore AD gas output. prodution through Expiration of the qualifying period for the tax redit has redued drilling ativities, whih will Improvements in both seismi tehnology and drilling likely affet the future volume of oalbed methane prodution methods ould give the Permian Basin new life during the late in both the Rokies and San Juan Basin, another region whih 1990s. One play, Texas Val Verde Basin, a sub-basin within is the leading U.S. produer of oalbed methane. The Roky the Permian, may have world-lass potential. While Val Mountain area is also a signifiant produer of AD gas, whih Verde has yielded finds suh as Pukett sine the 1950s, aounted for 12 to 15 perent of total regional output in the improved seismology has shown huge, previously unknown mid-1990s and about one-tenth of reserves. strutures in the Ellenburger formation and thrusted roks extending further east and north in Val Verde than previously Proved gas reserves in the Roky Mountain area grew by onerealized. Thrusted Shawn reservoirs, limestones that produe third from 16.0 trillion ubi feet (Tf) in 1990 to 21.7 Tf in either from fratured intervals or reefs, are at 10,000 feet and 1996 (Table 3). Large reent reserve gains at the Big Pineyoffer more immediate eonomi opportunity than deeper LaBarge Field have made it the largest field in terms of plays. In addition, Wolfamp (also known as Canyon Sand) reserves in Wyoming, while further reserve inreases are also is a low-risk, limited-potential play that is popular beause of likely to ome from the Madden Field and Moxa Arh suess rates of 90 perent in some ases. Extension. The Madden Field ould beome a very profitable play beause it might be possible to draw most of its gas out The potential from these plays, ombined with one of the of the formation through just one or two holes drilled at the highest surplus deliverability measures among produing top of the reservoirs. The Moxa Arh Extension ranks high in regions (an estimated 18 perent in 1996), should help to raise terms of gas produed per drilling dollar, but this does not Permian Basin gas prodution more than 10 perent between inlude heavy assoiated osts of fraturing the tight 1996 and 2000 to 5.2 Bf per day (1.9 Tf per year) (Table 2). formations that are ommon to this play. Other possible soures of inreased gas in the near term inlude oalbed methane in the Powder River play of Wyoming, where Roky Mountain Area produtive apaity rose from near zero in 1990 to 28 million ubi feet per day in 1996, with at least another 35 million ubi feet per day waiting for onnetion and pipeline hookup. The Roky Mountain area, inluding Colorado, Utah, and Wyoming, was one of the fastest-growing U.S. produing regions between 1990 and 1996 and has the potential for further output gains through Gas prodution inreased nearly two-thirds sine 1990 from 2.5 Bf per day (0.9 Tf per year) to 4.1 Bf per day (1.5 Tf per year) in 1996 (Table 2). Major plays in the Rokies inlude the Wind River Basin, the Labarge and Big Piney Projets, the Overthrust Belt, the Green River Basin, and the Powder River Basin. The Roky Mountain area is one of the newest major gas produing regions in the United States in terms of average field age, with most of the leading fields dating from the 1960s or later. The top produing fields in 1996 inluded Wattenburg in Colorado (0.24 Bf per day), Anshutz Ranh East in Utah/Wyoming (0.23 Bf per day), Whitney Canyon- Carter Creek in Wyoming (0.22 Bf per day), and Bruff in Wyoming (0.14 Bf per day). 29 As a result of reserve growth, the 1996 reserve-to-prodution ratio in the Roky Mountain area was among the highest in the lower 48 States at 14 (Table 3). Large reserves and output from new finds are expeted to ontribute to an 11-perent growth in Rokies gas prodution between 1996 and 2000 to around 4.6 Bf per day (1.7 Tf per year) in the latter year (Table 2). The rate of growth in Rokies gas output during the latter half of the 1990s is quite impressive given the number of impeding fators. Suh fators inlude the phaseout of the oalbed methane tax redit, saturation of Western markets, and the ost of building additional pipeline apaity to rediret more Rokies gas eastward towards high-demand markets, rather than due to any shortage of gas supplies. East Texas U.S. Crude Oil, Natural Gas, and 29 Natural Gas Liquids Reserves, Annual Report 1996 (Washington, DC, Deember 1997), p. 58. The East Texas region inludes Northeast Texas (Railroad Commission Distrits 5 and 6) and northern Louisiana. Its gas

28 Figure 4. U.S. Coalbed Methane Output, New Mexio 500 Billion Cubi Feet Colorado 100 Alabama Other Note: Other inludes Kansas, Oklahoma, Pennsylvania, Utah, Virginia, West Virginia, and Wyoming. Soure:, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 (Deember 1997). prodution inreased by one-tenth from 3.0 Bf per day mainly aounted for by two giant gas fields Basin and (1.1 Tf per year) in 1990 to 3.2 Bf per day (1.2 Tf per Blano that are two of the three largest in the lower 48 year) in 1996 (Table 2). Nearly one-half of prodution and States. The Basin Field, first drilled in 1947, was formed in over one-half of reserves in East Texas are aounted for by February 1961 by ombining several existing fields. The five fields: Carthage, Oak Hill, Willow Springs, Whelan, and Blano Field enompasses muh of the entral San Juan Hawkins. Carthage is the largest among them; in 1996, it Basin. produed Bf (wet gas, 0.56 Bf per day) and was the fifth largest U.S. gas field that year in terms of prodution. Muh of the inrease in gas prodution in the San Juan Basin during the 1990s has ome from oalbed methane wells. East Texas is one of the few onshore regions to register Prodution gains were strongest until the end of 1992, when substantial new field finds in reent years. Drilling in the phase-out of the oalbed methane tax redit began. Coalbed Cotton Valley lime reef play resulted in 25 disoveries methane prodution grew further in the years 1993 through reported out of 45 wells as of mid-1997 for a 55-perent 1996, owing to subsequent ompletion of wells spudded prior suess rate. At least 550 Bf of reserves have been found at to the tax redit deadline and as these wells proeeded the Cotton Valley Lime reef play, helping to expand the through the dewatering phase early in their prodution yle. region s reserves 7 perent to 11.1 Tf in 1996 after little San Juan Basin prodution inreases were also the result of hange between 1990 and Overall, East Texas gas well reompletions in the basin s deeper tight sands output is likely to inrease moderately by about 0.1 Bf per formations as operators employed new tehnologies to day to just under 1.2 Tf per year in inrease gas flow. San Juan Basin The San Juan Basin in northwestern New Mexio, like the Rokies, has substantially inreased prodution sine the late 1980s. Prodution almost doubled between 1990 and 1996 to 2.7 Bf per day (1.0 Tf per year) in 1996 (Table 2) and is Expiration of the oalbed methane tax redit had an immediate impat on San Juan Basin proved reserves, whih ontrated 13 perent between 1992 and 1996 (in part beause of downward revisions as some oalbed fields were onsidered no longer eonomial, espeially in a pipeline onstrained market) after expanding by a similar perentage between 1990 and This left the region s reserves at

29 13.7 trillion ubi feet in 1996, ompared with 14.0 in expeted to far exeed the expeted modest inrement to Stagnant reserves are not likely to limit the San Juan Basin s Appalahian Basin prodution during the 1997 through 2000 gas prodution in the near term, beause its reserves still period, attrative opportunities are likely for gas suppliers represent almost 14 years worth of prodution (well above from other regions of the lower 48 and from Canada. the U.S. average). Gas output is projeted to inrease about 3 perent per year on average during the late 1990s to 3.0 Bf per day (1.1 Tf per year) in 2000 as a result of redued oalbed methane ativity, well below its double-digit annual Canadian Supplies growth rate during the early 1990s. As with the Rokies region, the major onstraints on future growth of gas prodution in the San Juan Basin are more related to market onditions and infrastruture than to physial output apability. With peak produtive apaity utilization in the San Juan Basin running below 80 perent in the mid-1990s, surplus deliverability was the highest of any major gas-produing basin at over 20 perent. Thus, a major determinant of future gas output here is likely to be the pae of expansion of pipeline apaity to arry the gas to major markets in the Northeast and Midwest given the saturation of California and other Western markets. Appalahian Basin Sharp inreases in natural gas imports from Canada have made Canada the third most important soure of U.S. gas supplies after the offshore and Gulf Coast regions. Various fators have ontributed to the strong growth in U.S. natural 31 gas imports from Canada over the past deade, inluding: The U.S.-Canadian Free Trade Agreement (CFTA) of 1988 that prohibited most trade restritions on energy The Appalahian Basin extends from the Middle Atlanti to produts. the South Atlanti Census Bureau divisions and is the largest gas-produing basin lose to major markets in the Northeast. Sine 1987, U.S. gas imports from Canada have nearly tripled This region is a minor produer of gas, providing only about to around 8 Bf per day (2.9 Tf per year) in 1996, 2 perent of total lower 48 gas supplies, but it is a major aounting for 13.5 perent of U.S. gas supplies. Growth was soure of gas for the large urban areas of the Northeast. swiftest between 1990 and 1995, when imports of Canadian Pennsylvania and West Virginia aount for the majority of gas inreased at a 14-perent average annual rate. Relative the Appalahian Basin s natural gas prodution, while prie movements helped to stimulate inreased U.S. gas Virginia has inreased prodution following sizable new imports from Canada, sine the average wellhead prie in the finds, inluding oalbed methane deposits. lower 48 hanged from being 11 perent heaper than imported Canadian gas in 1990 to being 11 perent more A portion of the region s 1.4 Bf per day gas output omes expensive by 1996 (Figure 5). from unonventional soures, suh as Devonian Shale. In Deember 1992, the National Petroleum Counil estimated Canada produed about 5.6 Tf of gas in 1996, equivalent to that the Devonian Shale in this area ontains about 27 Tf that about 30 perent of lower 48 prodution. Canadian gas 30 ould be produed using known tehnology. This ompares prodution is entered in the Western Canada sedimentary with proved reserves in 1996 of 7.7 Tf, whih is one-third basin, 95 perent of whih ours in the western provines of larger than the 1990 level mainly beause of the new finds in Alberta (83) and British Columbia (12). Total Canadian gas Virginia. prodution was 56 perent higher in 1996 than in 1990, while natural gas end-use onsumption in Canada grew by only Higher reserves raised the Appalahian region s ratio of perent during the same period. As a result, domesti use proved reserves to prodution to 15 in 1996, the highest in the of natural gas in Canada (47 perent of final gas sales ours lower 48. Suh a ratio indiates high likelihood of prodution inreases during the late 1990s, with Appalahian Basin gas output foreast to grow about 16 perent to 1.6 Bf per day (0.6 Tf per year) in With demand in the Northeast 30 National Petroleum Counil, The Potential for Natural Gas in the United States: Soure and Supply (1992), p The 1985 Agreement on Natural Gas Markets and Pries that hanged Canada s priing poliy from governmentadministered to market-oriented priing The market-based proedure for determining the surplus Canadian natural gas available for export that replaed the previous reserves-to-prodution (R/P) ratio proedure in For more detail see, Natural Gas 1996 Issues and Trends, DOE/EIA-0560(96) (Washington, DC, Deember 1996), p Canadian Assoiation of Petroleum Produers, CAPP 1996 Statistial Handbook (Calgary, Alberta, Canada, 1997), Tables 3.10a, 6.3a, and 9.1a.

30 Figure 5. Comparison of Average U.S. Natural Gas Wellhead Prie and Canadian Natural Gas import Prie, Average Canadian Gas Import Prie Average U.S. Wellhead Prie Prie in 1996 Dollars Prie Ratio Ratio of Canadian to U.S. Prie Note: Pries in 1996 dollars based on appropriate gross domesti produt (GDP) deflators as published in the Survey of Current Business (August 1997) and distributed on the Internet site Soure: (EIA), Natural Gas Annual (September 1997). in the eastern provines of Ontario and Quebe) fell ommerial prodution by late 1999 and ontribute from representing 60 perent of Canadian prodution in 1990 signifiantly to North Amerian gas supplies in the longer to only 49 perent in Sine 1990, the TransCanada term, although their impat on U.S. markets through 2000 Pipeline system has substantially inreased its apability to will be limited. move supplies from the Alberta/Saskathewan border (urrently 7.2 Bf per day during the winter) but not rapidly The rising importane of U.S. export markets to Canadian gas enough to meet both the growth in domesti demand and produers is illustrated by the fat that more than half of export apaity. As a result, TransCanada Pipeline and several Canadian gas prodution by the mid-1990s was destined for other firms have developed plans to expand domesti and export to the United States ompared with two-fifths in 1990 export apability over the next several years to meet the (Figure 6). In 1996, growth in Canadian gas exports to the demands of Western produers and ustomers in Canadian United States slowed to 2.4 perent primarily beause of Eastern markets. bottleneks resulting from existing pipeline apaity onstraints. Relative prie data show that pries for U.S. While the more than 50-perent growth in Canadian gas imports of Canadian gas in 1996 ontinued to deline relative prodution redued the ountry s reserves-to-prodution ratio to the average wellhead prie in the lower 48. The downward from almost 26 in 1990 to 12 in 1996, the Canadian Gas movement in the prie for Canadian gas relative to the U.S. Potential Committee has estimated remaining marketable gas, prie was influened also by a signifiant shift in the inluding disovered reserves and undisovered potential in exhange rate, with the Canadian dollar falling from $0.86US established exploration plays and oalbed methane, at 34 in 1990 to $0.73US in Favorable prie trends 33 about 570 trillion ubi feet. This suggests that Canadian ombined with ontinued demand growth in the lower 48 are supplies are more than suffiient to meet expeted domesti likely to raise imports of Canadian gas by over one-third and export demands well past the year New gas finds between 1996 and 2000 to about 10.7 Bf per day (3.9 Tf off Canada s Atlanti shores are expeted to begin 35 per year) in Canadian Assoiation of Petroleum Produers, CAPP 1996 Statistial Handbook (Calgary, Alberta, Canada, 1997), Table Where future Canadian gas supply will originate, Oil and Gas Journal See, Annual Energy Outlook 1998 (Deember 15, 1997), p. 67. (Deember 1997), p. 118.

31 Figure 6. Canadian Gas Exports to the United States and Total Canadian Gas Prodution, To tal Billion Cubi Feet Canadian Gas Use Exports to United States Note: Canadian gas use was alulated by subtrating exports to the United States from total Canadian gas prodution. Soures: Canadian Gas Exports to United States:, Natural Gas Annual 1996 (September 1997) and earlier editions. Canadian Gas Prodution: Canadian Assoiation of Petroleum Produers (CAPP), Statistial Handbook 1996 (September 1997). Reeipt Capabilities Wellhead gas produtive apaity is only one of the elements neessary to meet U.S. natural gas demand. Beause major market areas are not usually loated in lose proximity to supply/prodution areas, moving the gas from the wellhead to market areas via pipeline is an important element of satisfying demand. The first leg of the transportation journey, whih is relevant to this hapter, requires adequate pipeline reeipt apability to failitate the movement of the natural gas from produing fields to the interstate pipeline system. In the United States, natural gas typially moves from major supply areas in Texas, Oklahoma, Louisiana, Wyoming, Kansas, Colorado, New Mexio and the Offshore Gulf of Mexio to the North and East. These routes saw a rise in average daily usage rates between 1990 and 1996, while usage rates fell sharply on pipelines heading westward into markets on the Paifi Coast, whih are saturated with gas from Canada. Additionally, the dramati inrease in gas imports from Canada during the past deade has opened up new supply routes from Western Canada to the lower 48, with the swiftest growth in route volume ourring into the Northeast. While wellhead gas produtive apaity and import apaity were suffiient to meet U.S. demand under normal weather onditions through the end of 1997, unusually high peak-day or peak-week heating or ooling demand required deliveries from storage or peak-day shaving. Limited pipeline reeipt apabilities in key prodution areas, suh as the Gulf of Mexio, the Northern Roky Mountains, and the San Juan Basin, ompromise the ability to meet peak demand. And with total U.S. gas supplies expeted to inrease by more than 12 perent between 1996 and 2000, the additional 7 Bf per day of supplies will require expansion of existing transport and storage apaity. Several projets have been proposed that will expand the reeipt apability of the interstate pipelines transporting natural gas from produing to onsuming areas in the United States, inluding gas imports via pipeline from Canada. Offshore and Onshore Gulf Northward The offshore and onshore Gulf region, whih together provide almost half of all natural gas produed in the lower 48, supply a large portion of this gas to other regions. These two regions aount for a large portion of the 12.6 Bf per day on average

32 transported from the Southeast to the Midwest and Northeast, to 1.5 Bf of daily deliverability from storage in the where rising shipments brought average usage rates to 82 to Southwest and up to 1 Bf per day from storage in the 86 perent in Northeast (mainly in New York and Pennsylvania). By moving the gas into markets suh as the Northeast during Despite an already well-developed gas infrastruture around nonpeak periods, natural gas marketers are better able to the Gulf, the last 6 years have seen an ongoing effort to build utilize existing pipelines. Beause storage is generally heaper suffiient offshore pipeline reeipt apaity to support the to build than laying new pipeline, this is an eonomially rapidly inreasing wellhead produtive apaity, partiularly attrative option for the short term. In the longer term, offshore. Offshore pipeline onstrution inreased more than however, marginal inreases from greater usage of existing 20 perent between 1990 and 1995, followed by ompletion pipelines may not be suffiient to aommodate the expeted of two large expansion projets in 1996 the Shell Gas magnitude of produed gas in ertain regions. Pipeline and the Centana Main Pass/Viosa Knoll Gathering System. Several new pipeline projets were ompleted in 1997, inluding the Garden Banks Offshore System, the From the Rokies and San Juan Basin Manta Ray Gathering System, the DIGS Main Pass Gathering Eastward System, the Disovery Pipeline, and the Nautilus Pipeline. As a result of this onstrution, nearly 20 Bf per day of pipeline apaity extends onshore from the offshore Gulf region, mostly to Louisiana. Major pipelines that reeive onshore and offshore Gulf gas for transportation to markets in the Northeast and Midwest inlude ANR, Columbia Gulf, Florida Gas, Koh Gateway, Southern Natural Gas, Tennessee Gas, Texas Eastern, Transontinental, and Trunkline systems. Some of these pipeline systems, notably Tennessee and Texas Eastern, are very large and were operating at nearly full apaity in 1996 during peak periods. Despite ambitious pipeline expansion plans to bring an additional 3 Bf per day or more of offshore gas ashore at Alabama, Louisiana, and Mississippi by the year 2000, lak of adequate apaity to transport the gas to markets in the Northeast and Midwest ould hamper future gas deliverability from the Gulf. There are 10 proposed projets that would bring more than 1.6 Bf per day of additional gas ashore at Louisiana and about 1.5 Bf per day at Mississippi and Alabama (see Appendix B, Table B2). Potential bottleneks may arise further downstream as existing pipeline apaity into Mississippi and Arkansas is not expeted to expand by similar magnitude and ould fae average usage levels far in exess of 90 perent. An alternative solution, inreased reliane on storage, ould allow for inreased gas deliveries from the Gulf to the Northeast without adding new pipeline apaity. A number of new storage failities, inluding high-deliverability salt avern storage, are being built both in the Northeast near the onsuming markets and on the Gulf oast near offshore 36 prodution areas. New salt avern storage failities expeted to be built during the years 1998 through 2000 ould add up, U.S. Underground Storage of 36 Natural Gas in 1997, Natural Gas Monthly, DOE/EIA-0130(97/09) (Washington, DC, September 1997). Despite strong growth in prodution and reserves in the Roky Mountain area and in the San Juan Basin of New Mexio between 1990 and 1996, only a small portion of that prodution saw its way to Midwest or Northeast markets. Pipeline apability to move gas eastward from that area has been limited as traditionally the prodution has been targeted to Western markets. But with Western markets beoming saturated, interest has inreased in moving supplies eastward. While the northern Roky Mountain area has not experiened reeipt onstraints for supplies moving westward, it has been unable to gain aess to Eastern markets beause of limited pipeline reeipt apability. This onstraint is expeted to ease as eastern aess via the San Juan Basin has inreased and several expansion projets have been planned that will inrease pipeline apaity from the Roky Mountains to hubs serving the Midwest and East. Expansions ompleted in 1997 inluded KN Energy s Pony Express line from Wyoming to several long-haul pipelines running from the Permian Basin to the Midwest and expanded apaity from the Overthrust and Green River basins to the eastward-running Trailblazer Line. Suffiient new pipeline apaity is planned between 1998 and 2000 to aommodate the expeted prodution inreases in the Rokies and San Juan Basin areas (almost 0.8 Bf per day additional) without major bottleneks. Aording to 1996 data, the El Paso pipeline from the San Juan Basin of New Mexio into Texas alone had nearly 1 Bf per day of unused apaity on average. Along with ompletion of the TransColorado line ( 0.3 Bf per day) to the San Juan Basin running from Colorado s Pieane Basin, Southwestern Wyoming, and Utah s Paradox and Uinta basins, this suggests adequate reeipt apability for the antiipated inrease in San Juan Basin output during the next 3 years. The Natural Gas Pipeline Company of Ameria s Amarillo expansion would help move these new supplies to the East through Chiago from the Waha hub in Texas.

33 Tehnologial Improvements A deade of tehnologial improvements has redued finding osts, raised the size of finds, and opened new areas of exploration The ombined appliation of several new tehnologies over the last deade has ontributed to U.S. gas prodution gains during the 1990s in a number of ways. These tehnologies inlude enhanements to exploratory and developmental ativities, suh as 3-D seismi and ross-well seismi surveys, improved drilling tehniques through the use of horizontal and multi-lateral drilling, and new offshore prodution systems that inlude floating and subsea assemblies. Lower finding osts failitated by wider use of 3-D seismi surveys and other new tehnologies have redued prodution osts and ontributed to higher U.S. gas prodution during the 1990s.* Over the past deade, onshore finding osts have been ut by more than half, while offshore finding osts have fallen even more sharply. As a result, offshore finding osts onverged with onshore finding osts in the mid-1990s after more than a deade of exeeding them by a onsiderable margin (Figure 7). The nearly two-thirds redution of offshore finding osts between 1986 and 1996 was a major fator in the inreased profitability of offshore gas prodution beause offshore lifting osts are muh lower and omprise a smaller share of total prodution osts than with onshore prodution (Figure 8). New tehnologies have redefined deep water drilling opportunities in the Gulf of Mexio. In 1996, dry gas produtive apaity in the Federal Offshore Gulf of Mexio region was nearly 30 perent of the produtive apaity for the lower 48 States. The offshore region also had a higher average reserves addition per suessful well, averaging more than 16 Bf from 1992 through The importane of the offshore portion of total U.S. gas prodution is expeted to rise further through the year 2000 with new apaity due for startup from deep water and subsalt wells as well as ontinued gains in AD gas output. Beause of tehnologial hanges, deep water drilling is now taking plae at previously impossible water depths for example, Shell s Mensa at depths of more than 5,300 feet. Future plans all for even deeper drilling, with Shell s Couloumb and BAHA projets planned at 7,500 feet or more (Figure 9). The tehnologies ontributing to these breakthroughs inlude: 3-D Seismi Surveys - 3D seismi surveys are onduted by use of metiulously spaed vibration-deteting geophones to measure the feedbak from a sequene of experimental seismi disturbanes. Their use has greatly improved geologial interpretations and has led to a muh higher rate of suessful wildat drilling. Future innovation may inlude 4D seismi (essentially time-lapse 3D seismi), whih ould help improve flow models to optimize reovery. Cross-well Seismi Surveys - Cross-well seismi surveys are used to evaluate the geologial harateristis of terrain between wells. Cross-well seismi measures the vibrations deteted in one or more wells when widespetrum sound is produed at varying intensity in another well. The nature of the vibrations provides important information on the qualities of the intervening region. Horizontal Drilling - Originally employed onshore in the 1980s, horizontal drilling angles off the vertial to follow the path of a gas-produing formation. While more ostly than vertially ompleted wells, wells with horizontal ompletion segments often produe at rates 3 to 5 times that of vertial wells and may redue the unit osts of prodution by as muh as 50 perent. The first offshore horizontal wells were drilled in 1990 and have played an important role in exploiting gas reserves in the Gulf of Mexio. *The finding and lifting osts introdued here represent alulations for the major integrated oil- and gas-produing ompanies and the large independent firms inluded in the s Finanial Reporting System (FRS). The FRS ompanies are 24 major U.S. energy ompanies that are required to report finanial and operating developments annually to the on Form EIA-28, Finanial Reporting System, pursuant to Setion 205(h) of the Department of Energy Organization At.

34 Tehnologial Improvements (Continued) Multilateral Drilling - This drilling method involves drilling multiple horizontal well ompletion segments at different depths having varying harateristis (e.g., permeability) and allows for eonomial reovery of a greater portion of a given well s reserves under ertain onditions. Subsalt Drilling - Considerable gas deposits are believed to reside beneath large horizontal sheets of salt. While historially the salt sheets blurred seismi images and made it diffiult to drill suessfully for subsalt gas deposits, new tehnologies have sharpened seismi images and improved hanes of disovery. The first subsalt disovery to be ommerially developed was the 1993 Mahogany strike in 370 feet of water off the Louisiana oast. Subsequent disoveries, inluding the Teak, Agate, Chimihanga, Enhilada, and Gemini wells, suggest high future potential for offshore development of subsalt gas deposits. Floating Prodution Systems - Key to expansion of deep water gas exploration and development, floating prodution systems inlude floating platforms or strutures tethered to the sea floor. Their advantages over fixed platforms inlude deeper range in offshore waters, lower average osts over their produtive lives beause they an be towed to various loations, and greater tolerane of hurrianes and other inlement weather as they move ompliantly to waves. Two major types of floating systems are: Tension Leg Platform (TLP) - Consisting of a hull with exess buoyany that maintains tension in a tether mooring system, it behaves like an inverted pendulum that moves ompliantly to waves. Beause onventional TLPs have enountered problems in waters over 3,000 feet, various modifiations have been reated for deeper waters that inlude tension base TLPs, suspended TLPs, tension raft jakets (TRJs), and hybrid ompliant platforms (HCPs). The first TLP, Conoo s Jolliet at 1,720 feet of depth, ame onstream in Spar Prodution System - Consisting of a single point buoy tanker loading and mooring platform with a storage tank, the spar s stability is inreased beause its enter of buoyany is above its enter of gravity. In ontrast to a TLP, the spar s hull does not support the prodution risers; instead, two separate floats arry the weight of the risers. Spar tehnology offers operators a way to redue deep water prodution osts while still having surfae well ompletions. The first spar was introdued in 1997 at Oryx s Neptune in nearly 2,000 feet of Gulf water. Subsea Prodution Systems - Subsea prodution systems have found wider appliations in the Gulf of Mexio over the past 2 to 3 years as prodution moves into deeper water. By tying bak subsea wells to either floating prodution systems or platforms in shallower water, operators are able to develop wells, inluding smaller ones, that otherwise would not be eonomi. In deeper waters, some operators are using subsea prodution systems based on template and well luster designs. The Gulf s first subsea luster prodution system was installed at Popeye Field, whih started prodution in In an attempt to redue osts, subsea prodution systems are beoming smaller, more modular units, and greater emphasis is being plaed on retrievable subsea omponents.

35 Figure 7. Finding Costs for Natural Gas and Crude Oil, Dollars per BOE Offshore Onshore BOE = Barrels of oil equivalent. Note: Finding osts are 3-year weighted averages of exploration and development expenditures for oil and gas, onverted to BOE. Soure:, Performane Profiles of Major Energy Produers 1996 (January 1998) and earlier editions. Figure 8. Offshore and Onshore Prodution Costs for Natural Gas and Crude Oil, 1995 and Finding Costs Lifting Costs 1996 Dollars per BOE Offshore 1995 Offshore 1996 Onshore 1995 Onshore 1996 BOE = Barrels of oil equivalent. Note: Finding osts are 3-year weighted averages of exploration and development expenditures for oil and gas, onverted to BOE. Lifting (or prodution) osts are the out-of-poket osts of extrating oil and gas and inlude operating (diret lifting) osts and prodution taxes. Soure:, Performane Profiles of Major Energy Produers 1996 (January 1998).

36 Figure 9. Depth Reords in Deep Water Gulf Drilling 10,000 Water Depth in Feet 8,000 6,000 4,000 2,864 2,958 5,327 6,530 7,500 7,620 2,000 1,720 0 Jolliet Auger Mars - Mensa - King's Peak Natural Gas Fields Coulomb - Planned BAHA - Planned Note: Water depths (in feet) are noted for eah projet. Soure: Seventy U.S. Gulf deepwater fields awaiting development, 26 are in prodution, Offshore (September 1997), p. 39. Canada Southward Canadian gas is imported into four U.S. regions: the Midwest (with a 28-perent share of the total in 1996); the Central 37 States (17 perent); Northeast (20 perent); and the Paifi Northwest (35 perent). Expansion of Canadian pipeline apaity has not kept up with the rapid U.S. demand growth for Canadian gas, raising the average usage rate on pipelines transporting this gas to the United States from 77 perent in 1990 to 84 perent in Certain orridors, espeially from Canada to the U.S. Northeast and from Canada to the U.S. Midwest, were operating at or lose to full operational apaity in 1996 (see Chapter 3), suggesting that Canadian gas imports may be lose to maximum flow until additional apaity an be added. The small growth in U.S. gas imports from Canada in 1996 and 1997 (less than 1 perent) was due largely to deliverability limitations to the TransCanada system and other exporting systems rather than beause of Canadian supply limitations. Prodution apabilities in Western Canada, espeially in Alberta, exeed the amount of pipeline apaity now existing on the system in that area (about 10.6 Bf per 37 Most of the gas imported into the Central Region goes to the Midwest. day, of whih 7.1 Bf is direted toward Eastern Canada and the U.S. Midwest and Northeast). As a result, Canadian shippers have been unable to reah their full potential market to the east. Proposals to alleviate the situation onsist of at least 11 projets within Canada, whih would provide an additional 0.3 Bf per day to Canadian markets and 7.7 Bf per day to U.S. gas import apaity from Canada from 1998 through (About 4.5 Bf per day of import apaity was added from 1990 through 1997.) A number of these projets are ompeting for the same markets and will not be built in all likelihood. Even if only half of the proposed apaity is ompleted by 2000 (see Appendix B), it would aommodate the additional 2.8 Bf per day of projeted imports while easing bottleneks on the pipeline network. Moreover, on Deember 30, 1997, the Canada-Nova Sotia Offshore Petroleum Board approved the Sable Offshore Energy projet, whih is aimed at development of six gas fields ontaining an estimated 3 trillion ubi feet of gas. In light of these events, sales of Sable Island gas in U.S. markets appear likely before 2000, but they are unlikely to be large enough to affet gas deliverability to the lower 48 States appreiably during this period. The Maritimes & Northeast Pipeline (MNE) transportation projet will bring gas from the

37 Nova Sotian shelf offshore Sable Island to Eastern Canada and the United States. One other transportation projet, the Marine Line Subsea proposal, ontinues to be onsidered as a possible alternative to move this gas to Canadian and U.S. markets. Impliations for Downstream Markets Expanded pipeline apaity should move more gas eastward from the Roky Mountain area and San Juan Basin of New Mexio to markets in the Northeast and Midwest during the next few years, although inreased demand from within the Central Region ould absorb some of the additional gas supplies from these two produing areas (see Chapter 4). Even larger inreases in supplies are antiipated from Canadian gas imports moving southward and eastward and from Gulf supplies moving northward primarily towards the Northeast and Midwest. Oversupply of the Midwest market is possible, given the large apaity inreases planned from all three soures, while inreased supplies to the Northeast should help mitigate potential inreases in natural gas pries. Inreased use of storage, partiularly high-deliverability salt avern storage, is likely to play a role in stabilizing pries by better mathing seasonal demand with available gas supplies. In the longer term, inreased gas supplies from Nova Sotia are targeted primarily at the Northeast and Eastern Canada, potentially ontributing to further leveling of natural gas pries throughout North Ameria. Summary Natural gas prodution in the lower 48 States is foreast to rise 7.8 perent from an average of 50.1 billion ubi feet per day in 1996 to 54.0 billion ubi feet per day in 2000, with muh of the inrease oming from the offshore Gulf of Mexio, the Permian Basin, and the Roky Mountain area. A tehnologial revolution during the 1990s, led by 3-D seismi surveys, horizontal drilling, and new offshore platform designs, has opened up deeper water frontiers in the Gulf of Mexio while also yielding new opportunities in onshore produing regions. Additional pipeline apaity from produing areas in Western Canada to major markets in the U.S. Northeast and Midwest will allow natural gas imports from Canada to rise, ontributing to inreased U.S. gas supplies in the near term. Planned pipeline expansions through 2000 appear generally adequate to aommodate new lower 48 produtive apaity and inreased Canadian gas imports, although bottleneks may be aused by lak of suffiient apaity to arry antiipated new offshore gas prodution beyond onshore Louisiana and the fat that most of the pipeline expansions allowing for inreased Canadian imports are not due for ompletion before 1999 and Major expansions of underground storage underway in the Northeast and Midwest as well as along the Texas and Louisiana oasts ould help to avoid bottleneks for gas moving northward from the offshore and onshore Gulf and ensure adequate deliverability to the top U.S. gas markets.

38 3. Deliverability on the Interstate Network The United States has a omplex, extensive pipeline infra- national pipeline grid, allowing the system to operate in a struture for transporting natural gas from prodution areas to muh smoother manner. ultimate onsumers. More than 85 U.S. interstate pipeline ompanies operate almost 200,000 miles of transmission Although a few natural gas transportation orridors are lines, hundreds of ompressor stations, and numerous storage operating at lose to full utilization year round, the pipeline failities, allowing gas delivery throughout the lower network in North Ameria has demonstrated its apability to 48 States. The importane of the network is refleted in the meet the urrent level of demand. In addition, several fat that 27 of the lower 48 States are almost totally expansions are planned to alleviate those ases where dependent upon the interstate system for their gas supplies limitations exist, espeially along those orridors transporting (Appendix C, Table C2). Canadian gas into the United States. In fat some exess apaity ould develop along several orridors, although there Fifty of the interstate pipeline ompanies are lassified as probably will be some loal areas where available pipeline major systems by the Federal Energy Regulatory apaity will not math demand. Commission (FERC), in that they eah transported more than 50 million dekatherms (equivalent to about 66 billion ubi feet (Bf)) of natural gas in eah of the past 3 years. During Reent Changes Affeting the January 1996, the month of greatest gas onsumption that year, deliveries to end-use ustomers averaged 77 Bf per Pipeline Network day, with muh of the gas moving along these same 38 pipelines. The smaller interstate pipeline ompanies and the intrastate network (more than 200 systems) are also important, although their servies are regional in nature. In fat, some of the intrastate pipeline systems in Texas and Louisiana rival some of the interstate systems in apaity, volumes transported, and revenue generation. This hapter examines the apability of the interstate pipeline system to link prodution and market areas, fousing on pipeline operations along 10 distint orridors: 5 of whih extend from the Southwest, 3 from Canada, and 2 from the Roky Mountains. It identifies the various pipeline ompanies operating in eah orridor and disusses the hanges in apaity and usage that have ourred sine It also briefly desribes how some of the hanges that have ourred as a result of industry restruturing have affeted the way gas moves along the pipeline network. The natural gas pipeline network has grown substantially sine 1990, with more than 11.4 Bf per day of interregional apaity (a 15-perent inrease) added through the end of Meanwhile, the network has beome more interonneted, its routings more omplex, and its business operations more fluid. New types of failities, suh as market enters, and established operations, suh as underground storage failities, have beome further interwoven into the Based on total gas delivered to residential, ommerial, industrial and 38 eletri utility ustomers in the United States. Energy Information Administration, Natural Gas Monthly, DOE/EIA-0130(97/12) (Washington, DC, Deember 1997). Pipeline system operations have hanged radially during the past 10 years, partiularly sine 1992 when FERC issued Order 636. The order formalized the transition of interstate pipeline ompanies from sellers of natural gas to nondisriminatory transporters and mandated open aess to interstate storage failities. The resulting restruturing of the industry hanged how network resoures were being used and aused some shifts in transportation routes and trading and shipping arrangements. The inreased ompetitiveness of the marketplae has led to several new pipeline interonnetions as end users sought aess to the least expensive gas supplies. With pipeline ompanies no longer owning the gas they transport, end users beame responsible for making their own arrangements for purhasing and transporting natural gas. Sometimes the traditional pipeline link ould not aommodate the onsumers needs diretly and onsequently several new transportation relationships (interonnetions) developed. Storage has beome an inreasingly important omponent of overall pipeline and network operations. The interstate pipeline network depends upon a large number of underground storage sites to provide storage servies to pipeline shippers and as a means for maintaining system balanes and bakup. Underground storage provides the mehanism through whih a pipeline ompany an maintain ontrol over its throughput levels in an environment where it no longer has total ontrol over its reeipts and deliveries. Of the 410 underground storage sites operating in the United

39 States in 1996, almost half (190), representing more than trading at strategi points throughout the North Amerian 52 billion ubi feet of peak-day deliverability, were pipeline grid. Most of the points are loated in prodution owned by interstate pipeline ompanies or their areas, refleting the selling of gas by produers at various 39 affiliates. Another 39 of the 400 storage sites serve the gathering and pooling points. However, the number of interstate market although they are owned by points within market areas is growing as shippers independent operators or large loal natural gas demand more trading flexibility to handle imbalane distribution ompanies. The majority of sites owned by 41 situations during peak transportation periods. Currently, independent operators are linked to natural gas market there are almost 150 trading points defined on these enters. eletroni trading servies. In addition, many of these same points, and some others, are traked in the industry Market enters have proliferated during the 1990s trade press. For instane, Gas Daily, a widely irulated and are beoming inreasingly integrated into industry newsletter, publishes a daily prie index of the transportation network. Natural gas market enters natural gas trades based upon transations reported at are a reent development in North Ameria. Prior to approximately 120 points in North Ameria. 1990, only the Henry Hub site in southern Louisiana 40 loosely fit the urrent profile of a market enter. Today, Market enters and eletroni trading enters/points are at least 38 market enters are operating in the United rapidly beoming vital omponents in maintaining an effiient States and Canada, providing numerous interonnetions and smooth pipeline network operation in North Ameria. and routes to enhane transfers and movements of gas The vast majority of market and trading enters are loated at from prodution areas to markets. These enters provide either end of most of the transportation orridors disussed in a number of servies formerly provided by pipeline the following setions. Future growth, or lak thereof, within ompanies and also offer many of the new servies these orridors will beome a funtion of how muh ativity needed in today s market, suh as short-term gas loans or develops at these sites. Conversely, growth in demand within temporary gas parking. The types of flexibility demanded individual orridors would be neessary to support any of market enter servies is prediated upon the use of additional market and trading enters. high-deliverability (mostly salt avern) underground storage failities. Pratially all of the high-deliverability storage loated in North Ameria is aessible through or linked diretly to market enters. More than two-thirds of System Growth Sine 1990 market enters have some form of storage aess, The aommodations to hange in the restrutured industry aounting for about 47 perent of the working gas in brought about signifiant shifts in natural gas reeipt, North Ameria, or more than 2 trillion ubi feet. Market transport, and deliverability along the pipeline network. Sine enters also offer transportation (wheeling) servies, 1990, several new pipelines have been onstruted that have balaning, title transfer, gas trading, eletroni trading, improved ustomer aess to prodution soures (Figure 10). and administrative servies needed to omplete But, for the most part, muh of the new apaity added on the transations on behalf of the parties. network was an expansion to existing systems in order to inrease aess to new prodution soures or to new markets. The emergene of natural gas trading enters or trading points is also a reent development within the natural gas marketplae. Trading enters, whih sometimes represent the same physial points as a market enter or hub, have emerged with the growth of eletroni gas trading. Many enters also represent trading points that evolved from the natural gas spot market that first arose during the mid-1980's. At first, ommerial eletroni gas trading systems were assoiated with and available only through a few market enters, but now their marketability has been expanded as subsribers are being offered the opportunity to enat Between 1990 and the end of 1997, apaity additions on the long-haul orridors alone, whih link prodution and market areas, totaled approximately 12.4 billion ubi feet per day, 42 an inrease of about 17 perent. Capaity and deliverability additions made during the period fall into several ategories: 41 In fat, aording to Quiktrade L.L.C., one of the largest of the eletroni trading ompanies in volume traded, the Chiago trading point, in 1996 transated six times more business than the largest traded prodution 39, Form EIA-191, Underground Gas area point, NGPL Texas/Oklahoma. Storage Report. 42, EIAGIS-NG Geographi 40, Natural Gas 1996: Issues and Information System, Natural Gas Pipeline State Border Capaity, as of Trends, DOE/EIA-0560(96) (Washington, DC, Deember 1996), Chapter 3. Deember 1997.

40 Figure 10. Capaity of New Natural Gas Pipeline Systems Plaed in Servie in the United States Between 1990 and 1997 (Volumes in Million Cubi Feet per Day) Bluewater Pipeline 1995 (250 Bi-diretional) Empire Pipeline 1994 (500) Tusarora Pipeline 1995 (110) Iroquois Pipeline 1991 (850) Kern River Pipeline 1992 (750) Mojave Pipeline 1992 (450) TransColorado Pipeline 1996 (Southern Leg) (120) Crossroads Pipeline 1995 (250) Pony Express Pipeline 1997 (255) Nautilus Pipeline 1997 (600) Mobile Bay Pipeline 1993 (600) Garden Banks Offshore System 1997 DIGS Main Pass Gathering System 1997 (600) (200) Manta Ray Gathering System 1997 (300) Disovery Pipeline 1997 (600) Note: Crossroads and Pony Express pipelines were onversions of existing oil pipelines to natural gas usage. Soure:, EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity and Natural Gas Proposed Pipeline Constrution Database, as of Deember New pipeline systems built either to transport gas from 43 apaity was brought into servie. In 1994, 1995, and 1996, expanding prodution areas or to servie new market new apaity additions fell off dramatially (totaling only areas 4.9 Bf per day over the 3 years). The low level of pipeline expansions in those years reflets deisions made as far bak Expansion of existing systems to aommodate growing as 1992 and earlier, just as the natural gas marketplae was ustomer demand but aessing supplies already linked undergoing a major restruturing and expanding deregulation. to the network Unertainty about the needs of this new market most likely kept the number of proposed projets to a minimum. In Expansion of an existing system to aommodate shipper addition, as market onditions hanged so did some projet supplies transported via other pipeline systems plans. Expansions of short-haul loal delivery lines to link with In 1997, more than 40 pipeline projets were ompleted, the new ustomers who bypass loal natural gas distribution largest number sine 1993, adding 6.3 Bf per day of apaity ompanies overall while adding 0.5 Bf per day to interregional deliverability and 3.9 Bf to intraregional deliverability. A Expansions of pipeline systems in areas where produtive major portion of the new pipeline apaity represented apaity was greater than existing transportation inreased reeipt apability in expanding supply areas. For apaity. instane, the largest projets were in the Gulf of Mexio (3.2 Bf per day) as offshore and deep-water development Most of the pipeline expansions sine 1990 took plae efforts in the area ontinue to expand. In addition, several between 1991 and 1993, when approximately 17.2 billion ubi feet (Bf) per day of additional interstate pipeline The total apaity represented by the major interstate pipeline 43 onstrution projets during the period tabulated on a per projet basis.

41 major projets were ompleted that expanded aess to the routes extend from the produing areas of the Southwest, Wind River and Powder River basins of the Roky Mountain three routes enter the United States from Canada, and two area by more than 0.5 Bf per day. The first new export lines originate in the Roky Mountains. For this analysis the to Mexio to be ompleted in 5 years were also plaed in 10 orridors have been roughly delineated as follows servie during (Figure 12): The greatest inrease in apaity sine 1990 ourred on those From the Southwest routes between Canada and the U.S. Northeast, 1.9 Bf per day, or 412 perent (Table 7). This was brought about with Southwest Southeast: from the area of East Texas, the ompletion of several new pipelines and expansions to Louisiana, Gulf of Mexio, and Mississippi to the several import stations, almost exlusively in New York State Southeastern States. (Figure 11). The largest inrease in domesti apaity was between the Southwestern and Southeastern States, 1.0 Bf Southwest Northeast: from the area of East Texas, per day. This inrease was driven primarily by the growth in Louisiana, Gulf of Mexio, and Mississippi to the U.S. eletri power and industrial demand for natural gas in the Northeast (via the Southeast Region). Southeast, partiularly in Florida. 44 Southwest Midwest: from the area of East Texas, The magnitude of pipeline expansion sine 1990 an best be Louisiana, Gulf of Mexio, and Arkansas to the illustrated in onjuntion with the natural gas pipeline Midwest. transportation patterns that have emerged in North Ameria over the years (Figure 12). In the early 1990s, three Southwest Panhandle Midwest: from the area of geographi regions were the primary fous of apaity southwestern Texas, the Texas and Oklahoma expansion: the Western, Midwest, and Northeast regions. All panhandles, western Arkansas, and southwestern three regions shared one ommon element, greater aess to Kansas to the Midwest. Canadian supplies. In addition, the Western Region was the target of expansions out of the Southwest Region, as new Southwest Western: from the area of southwestern prodution soures were developed in the San Juan Basin of Texas (Permian Basin) and northern New Mexio New Mexio and demand for natural gas in California was (San Juan Basin) to the Western States, primarily expeted to grow substantially during the deade. California. Through the year 2000, U.S. aess to Canadian prodution From Canada is expeted to ontinue to expand at a rate never before seen, while major servie expansion to the Western Region appears Canada Midwest: from the area of Western Canada to have ended. During the next several years, the emphasis to Midwestern markets in the United States. will shift to expanding natural gas transportation apabilities from the Roky Mountain, New Mexio, and West Texas Canada Northeast: from the area of Western Canada areas eastward to link with pipeline systems reahing the to Northeastern markets in the United States. Midwest and Northeast markets. With the ompletion of this effort, the interstate natural gas pipeline network will ome Canada Western: from the area of Western Canada loser to being a national grid where prodution from almost to Western markets in the United States. any part of the ountry an find a route to ustomers in almost any area. It will fill the gap in the national network that to From the Roky Mountains some extent has left the Roky Mountain and Western natural gas produers isolated from ertain markets (see Chapter 2). Roky Mountains Western: From the Roky Mountain area of Utah, Colorado, and Wyoming to the Western States, primarily Nevada and California with support for markets in Oregon and Washington. Major Transportation Corridors The national natural gas delivery network is quite intriate and expansive, but most of the major transportation routes an be broadly ategorized into 10 distint orridors. Five major Roky Mountains Midwest: From the Roky Mountain area to the Midwest, inluding markets in Iowa, Missouri, and eastern Kansas. Only a small part of this additional apaity, 342 MMf per day, 44 represented apaity that ontinued on to the Northeast or Midwest regions.

42 Table 7. Interregional Pipeline Export Capaity, Average Daily Flows, and Usage Rates, 1990 and 1996 Capaity Average Flow Usage Rate 1 Sending Reeiving (MMf per Day) (MMf per Day) (perent) Region Region Perent Perent Change Change Change Canada Central 1,254 1, , Midwest 2,161 3, ,733 2, Northeast 467 2, , Western 2,421 3, ,874 3, Total from Region 6,303 10, ,857 9, Mexio Southwest Total from Region Central Canada Midwest 8,988 9, ,684 7, Southwest 1,283 2, , Western 365 1, Total from Region 10,702 13, ,495 9, Midwest Canada 1,211 2, , Central 1,765 2, , Northeast 4,584 4, ,474 4, Total from Region 7,560 9, ,409 7, Northeast Midwest 2,024 2, Southeast Total from Region 2,124 2, Southeast Midwest 9,645 9, ,134 8, Northeast 4,971 5, ,091 4, Southwest Total from Region 15,021 15, ,300 12, Southwest Central 8,555 8, ,119 4, Mexio Southeast 19,801 20, ,613 16, Western 4,340 5, ,910 2, Total from Region 33,050 35, ,680 23, Western Central Mexio Total from Region Usage rate shown may not equal the average daily flows divided by apaity beause in some ases no throughput volumes were reported 1 for known border rossings. This apaity was not inluded in the omputation of usage rate. MMf = Million ubi feet. -- = Not appliable. Soures: (EIA). Pipeline Capaity: EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember Average Flow: Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition. Usage Rate: Offie of Oil and Gas, derived from Pipeline Capaity and Average Flow.

43 Figure 11. Region-to-Region Natural Gas Pipeline Capaity, 1990 and 1996 (Volumes in Million Cubi Feet per Day) Western 3,786 (2,421) 45% 298 (250) 19% 1,194 (365) 227% 2,114 (1,283) 64% Central 66 (66) 0% 1,563 (1,254) 25% Midwest 2,354 (1,765) 33% 9,879 (8,988) 9% 3,049 (2,161) 41% 2,543 (1,211) 110% 4,887 (4,584) 7% 2,038 (2,024) 1% Northeast 2,393 (467) 412% 520 (100) 418% 45 (45) 0% NN = 1996 (NN) = 1990 N% = Perent Change 5,351 (4,340) 23% Southwest 350 (350) 0% 8,609 (8,555) 1% 844 (354) 138% 20,846 (19,801) 5% 9,821 (9,645) 2% 405 (405) 0% 5,149 (4,971) 4% Southeast Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember Figure 12. Major Natural Gas Transportation Corridors in the United States and Canada, Capaity (Million Cubi Feet per Day (MMf/d)) 15,000 12,000 9,000 6,000 3,000 0 N = Corridor ID = Less than 100 MMf/d Capaity Note: The 10 transportation orridors are: (1) Southwest Southeast, (2) Southwest Northeast, (3) Southwest Midwest, (4) Southwest Panhandle Midwest, (5) Southwest Western, (6) Canada Midwest, (7) Canada Northeast, (8) Canada Western, (9) Roky Mountains Western, and (10) Roky Mountains Midwest. Soure:, EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember 1997.

44 While these 10 orridors onstitute the bulk of the longdistane transportation routes, a number of regional pipeline systems also serve markets within either the supply region itself or the major market areas. For instane, one of the largest pipeline systems within the Southwest supply region is NORAM Gas Transmission Company; within the Northeast market region, Columbia Gas Transmission Company is a major interstate transporter/distributor of natural gas (see Chapter 4 for a regional breakout of pipeline servie areas). Originating Regions The largest amount of natural gas pipeline apaity exists on those systems that link the prodution areas of the U.S. Southwest with the other regions of the ountry. Capaity exiting the region in 1996 was nearly 36 billion ubi feet (Bf) per day. Between 1990 and the end of 1996, total export apaity from the region grew by 8 perent or 2.6 Bf per day (Table 7). Export apaity from the Central Region, whih inludes the Roky Mountain prodution areas, was slightly more than 13.3 Bf per day in 1996, most of whih is direted to the U.S. Midwest (9.9 Bf per day). About 86 perent of this latter figure, however, represents apaity that originates outside the region (from the Southwestern States or at the Canadian border) and merely traverses the region. Canadian export apaity into the United States in 1996 stood at about 10.8 Bf per day. That figure represents a growth of 69 perent (4.5 Bf per day) sine 1990, with muh of the additional export apaity reahing into the U.S. Northeast. The motivation behind many of the expansion projets ompleted in these exporting regions from 1991 through 1996 was to improve deliverability from apaity-onstrained prodution areas and/or provide alternative routing opportunities to shippers seeking aess to new markets. More than 20 of the major interstate pipelines originate in the Southwest. Some extend to the Southeast through Louisiana and Mississippi, others to the Central and Midwestern States through Texas, Oklahoma, and Arkansas, and to the Western States through New Mexio. This area of the ountry exports about 60 perent (8.6 trillion ubi feet in 1996) of its prodution, whih is 58 perent of the total natural gas 45 onsumed elsewhere in the lower 48 States. Pipelines exiting the region have the apaity to aommodate as muh as 35.7 Bf per day: 58 perent to the Southeast Region, 24 perent to the Central Region, 15 perent to the Western Region, and the rest to Mexio (Figure 11). Muh of the pipeline apaity direted toward the Southeast traverses the region en route to Midwestern and Northeastern markets. To a lesser degree, this is also true for the pipeline apaity exiting to the midsetion of the ountry, muh of whih is ultimately destined for the Midwestern States. The Southwestern States also have a large number of underground storage failities, most of whih were one used to store exess natural gas prodution during months of low 46 onsumption. While still true, prodution storage servie is now only one of the funtions provided by these sites. A growing amount of the storage in the region is highdeliverability (salt dome) storage, whih allows a rapid drawdown of inventory (within 10 days or one a month) and quik shifts from injetion to withdrawal mode. This type of storage is highly omplementary of the needs of shippers, who under today s rules must manage their own aounts and avoid ostly pipeline imbalane penalties and the other vagaries of a more ompetitive marketplae. Total working gas storage apaity in the Southwest (over 982 billion ubi feet) is the seond highest of the six regions (Appendix C, Table C1). In the Central Region, only one major interstate pipeline provides transportation servies diretly to another region, Kern River Transmission Company. All the others operate primarily within the Central Region itself. Shippers using these lines to move supplies outside the region take advantage of the interonnetions these lines have with the interstate pipelines traversing the region, prinipally those oming out of the Southwest Region. Transportation Corridors Southwest-Southeast Two routes extend from the Southwest to the Southeast Two fairly distint suborridors extend into the Southeast Region from the Southwest: one goes eastward into Mississippi and ontinues further east, and the seond goes northward into Tennessee and Kentuky (Figure 12). Along the first route, there are three major interstate pipeline ompanies that operate almost exlusively within the Southeast Region Florida Gas Transmission Company (FGT), Koh Gateway Pipeline Company (Koh), and Southern Natural Gas Company (SONAT) (Table 8). Together they an handle at least 4.9 billion ubi feet (Bf) per day for shippers in the region. 46, U.S. Underground Storage of 45 For purposes of this disussion, exports pertain to all volumes leaving a Natural Gas in 1997: Existing and Proposed, Natural Gas Monthly, region for another region or ountry. DOE/EIA-0130(97/09) (Washington, DC, September 1997).

45 Table 8. Natural Gas Transportation Corridors and Assoiated Major Pipeline Systems, 1996 Other Number of Number of Average Day Capaity Regions Delivery Interonnet Utilization (MMf/d) Corridor / Pipeline Name Crossed Points Points Rate Wide Point Southwest-Southeast Florida Gas Transmission Co None ,475 Koh Gateway Pipeline Co None ,134 Southern Natural Gas Co None ,250 Texas Gas Transmission Corp None ,163 Transontinental Gas Pipeline Co None , Southwest-Northeast Columbia Gulf Transmission Co Southeast ,063 Tennessee Gas Pipeline Co Southeast ,671 Texas Eastern Transmission Corp Southeast ,850 Transontinental Gas Pipeline Co Southeast , Southwest-Midwest ANR Pipeline Co Southeast ,013 Midwestern Gas Transmission Co Southeast Natural Gas Pipeline Co of Ameria Central ,893 Texas Gas Transmission Corp Southeast ,509 Texas Eastern Transmission Corp Southeast Trunkline Gas Co Southeast , Southwest Panhandle-Midwest ANR Pipeline Co Central Natural Gas Pipeline Co of Ameria Central ,765 Northern Natural Gas Co Central ,500 Panhandle Eastern Pipeline Co Central , Southwest-Western El Paso Natural Gas Co None ,261 Transwestern Gas Pipeline Co None , Canada-Midwest Foothills Pipeline Co LTD (Canada) None 0 1 NA 1,675 Great Lakes Gas Transmission Co (U.S.) None ,286 Northern Border Pipeline Co (U.S.) Central ,675 TransCanada Pipeline LTD (Canada) None 0 2 NA 7,100 Viking Gas Transmission Co (U.S.) None Canada-Northeast Empire Pipeline Co (U.S.) None NA NA NA 500 Granite State Gas Transmission Co (U.S.) None NA NA Iroquois Gas Pipeline Co (U.S.) None Tennessee Gas Pipeline Co (U.S.) None TransCanada Pipeline LTD (Canada) None 4 3 NA 3, Canada-Western Alberta Natural Gas LTD (Canada) None 0 1 NA 1,360 Foothills Pipeline Co LTD (Canada) None 0 1 NA 1,094 Northwest Pipeline Corp (U.S.) None ,289 Paifi Gas Transmission Co (U.S.) None ,454 Tusarora Gas Transmission Co. (U.S.) None 5 1 NA 110 Westoast Gas Transmission LTD None 1 1 NA 1, Roky Mountains-Western Kern River Gas Transmission Co None Roky Mountains-Midwest Trailblazer Pipeline System None KN Interstate Gas Co None Williams Natural Gas Co None Represents the number of delivery points or major pipeline interonnetions along the setion(s) of the pipeline systems assoiated with and within the respetive orridor. 2 Based on the sum of the State rossing point apaities of the respetive pipeline divided by the sum of average daily flows at the same points. 3 Represents the apaity (throughput apability) of the pipeline system at its maximum within the orridor. NA = Not available. MMf/d = Million ubi feet per day. Soures: Federal Energy Regulatory Commission, FERC 567 Capaity Report, System Flow Diagram. (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember 1997.

46 Varying amounts of apaity on several other large interstate oinided with the 655 MMf per day expansion of the FGT pipelines that follow this suborridor also serve limited system and the multi-phased expansion on the southern markets in the region. For instane, Transontinental Gas portion of the Transo system, totaling 220 MMf per day. Pipeline Company (Transo) serves ustomers in Georgia, South Carolina, and North Carolina as it ontinues along its FGT expanded its system to provide additional servie to the route up the east oast (Appendix A, Figure A4). However, State s eletri power generation setor and to a growing this servie only represents about 1.1 Bf per day, or industrial setor; natural gas use in these setors grew at an 30 perent, of the 3.5 Bf per day found on the Transo annual rate of 9.8 and 8.7 perent, respetively, between 1990 system as it enters the region. Yet, in North Carolina it is and Capaity utilization on the FGT system on its peak essentially the only soure of natural gas supplies to the State. day in 1995 was 102 perent (Figure 17, Chapter 4). During its month of greatest throughput (July), average utilization Along the seond suborridor, one pipeline ompany was 97 perent, while during its lowest month (February) it predominates, at least in terms of delivery points, Texas Gas fell to only 66 perent. FGT is unique in that its highest usage Transmission Company (TGT). While this system extends rates our during the summer months, refleting the strong into the Midwest Region, more than 70 perent of its delivery eletri generation (for air onditioning) needs within this points are loated in the States of Kentuky and Tennessee. warm region. TGT provides substantial deliveries to underground storage failities in northern Kentuky that supplement supplies to the Tennessee Gas Pipeline Company (Tenneo) added apaity loal market and to the Midwest Region during the heating within this orridor to improve its overall apability to serve season. ustomers in the Northeast. While its several mainlines were already quite large in 1990, the added apaity represented a Tennessee Gas Pipeline Company (Tenneo) and Texas sizeable perentage inrease to overall apaity along the Eastern Transmission Company (TETCO) are two additional orridor. Tenneo inreased its apaity on the route by systems operating along this suborridor, but most of their 19 perent (126 MMf per day) leaving the prodution area delivery points are outside the Southeast Region. Tenneo, of the Southwest (Appendix A, Table A4). however, is the prinipal supplier of gas to two regional interstate pipelines: MidCoast Pipeline (formerly the Average daily utilization rates on other pipelines in this Alabama-Tennessee Natural Gas Company) mostly operating orridor in 1995 ranged between 40 and 84 perent. The most in northern Alabama, and the East Tennessee Gas Company highly utilized was the FGT system, whih had a 66-perent (Tennessee and Virginia). Nevertheless, these deliveries usage rate during the off-peak periods and lose to full represent only about 0.6 Bf (peak-day) out of a total 2.3 Bf apaity during its peak servie period. The Transo system deliverability available per day on the Tenneo system. operated at about 83 perent on average, while during its peak periods operated at about 99 perent and 81 perent during Capaity along the eastern suborridor inreased by about the summer off-peak period (see Chapter 4). 5 perent between 1991 and 1996, primarily beause of a substantial expansion on a major part of the Florida Gas The underground storage failities loated along this orridor Transmission system (up to 80 perent). In addition, while the are defined by their loation. Those failities at the orridor s Transontinental Gas Pipeline system is not primarily a southern end in Louisiana, Mississippi, and Alabama are regional supplier, a major portion of its expansions during this mainly high-deliverability salt storage sites to support period were direted toward servie along this orridor rather shippers and traders who want to aquire supplies for than on its Northeast regional setion. Transo s expansion shipment to market (Appendix C, Table C1). Of the 9.3 Bf during the period inluded a large apaity addition (0.4 Bf of daily storage deliverability (withdrawal) available in the per day) to new ustomers in northern North Carolina. The area, 46 perent is from salt avern sites. This feature addition atually brought servie southward, out of Virginia, provides shippers using these orridors aess to very flexible from Transo s northbound mainline. storage, whih an be used to enhane their deliverability shedule, avoid transportation imbalanes, and support any One new pipeline, the Mobile Bay Pipeline system gas trading or hedging ativities they may wish to engage in. (600 million ubi feet (MMf) per day), was added within this orridor in It was only the seond pipeline built in In northwestern Kentuky, along the western suborridor, the Gulf of Mexio that terminates in the Southeast Region storage failities are devoted primarily to providing seasonal (the first being the Chandeleur Pipeline, 275 MMf per day). supplies. They are supported, for the most part, by deliveries The system interonnets with both the Transontinental Gas from the Texas Gas Transmission system. The majority of the Pipeline (Transo) and Florida Gas Transmission (FGT) storage in Mississippi and Alabama is available to shippers systems loated in Alabama. The ompletion of this pipeline using either suborridor.

47 The prinipal pipeline expansions proposed along, or within, inrease was on the Tennessee Gas Pipeline system, whih this orridor through 2000 represent greater aess to Gulf of rose from 80 to 86 perent. Mexio supplies and improvements to servie within the Southeast Region (Appendix B, Table B2). Projets slated to During wintertime peak periods, eah of the systems are provide new or improved aess to Gulf of Mexio supplies almost fully utilized. During the summer months, however, amount to about 1.7 Bf per day or 54 perent of the regional usage rates for the pipeline systems operating along this projets urrently proposed. Stritly onshore, the SONAT orridor tend to drop substantially. Exept for the Columbia system will add 141 MMf per day to its northern setion, Gulf Transmission system, whih operated at lose to while Transo will upgrade its system with a short-haul 100 perent year-round during 1995, the summertime (system 400 MMf per day pipeline link to a new liquefied natural gas wide) usage rates ranged from 49 perent for Texas Eastern s faility in North Carolina. In addition, Transo plans to system to 81 perent for Transo s system. The prinipal update its failities along this route to support the fator affeting summertime usage rates on several of these development of two new regional pipeline systems, the pipeline systems is the demand for gas to refill underground Cardinal Pipeline in North Carolina (140 MMf per day) and storage sites in the States of West Virginia and Pennsylvania, Cumberland Pipeline serving Tennessee and Georgia and, to some degree, Ohio and New York as well. During the (200 MMf per day). past several years, the refill rate and level of total (storage) working gas inventory prior to the heating season has fallen Southwest-Northeast as inventory management praties have hanged. This trend is refleted in the lower off-peak usage rates on some of the The main flow of U.S. gas is toward the Northeast affeted pipeline systems. The Southwest-to-Northeast orridor onsists of two routes. The first extends from East Texas and Louisiana northeastward through Mississippi, Tennessee, Kentuky, and parts of Ohio to enter the Northeast Region via West Virginia or Pennsylvania (Figure 12). The seond route begins as the first but then extends northeastward from Mississippi via the east oast States and enters Virginia from the south. The prinipal interstate pipeline systems operating along the orridor inlude Tennessee Gas, Columbia Gulf Transmission, and Texas Eastern Transmission on the western segment, and Transontinental Gas Pipeline on the eastern segment. These four pipeline ompanies represent approximately 9.3 Bf per day of total apaity, making this orridor the largest of the major transportation orridors in North Ameria. Sine 1990, apaity on this orridor inreased only slightly, about 500 MMf per day. Most of that, 300 MMf per day, ourred on the Texas Eastern Transmission system as improvements were made to the links between its eastern seaboard network and its Midwest interonnetions. Transontinental Gas Pipeline system inreased its apaity by 310 MMf per day, but little of this expansion affeted its system north of Virginia. The average utilization rates for the pipelines operating along this orridor ranged from 73 to 86 perent in 1996, for an overall average rate of 82 perent (Appendix A). That overall rate was the same as in With the exeption of Transontinental Gas Pipeline system, whih had a slight drop in utilization between the two omparison years, usage on eah of the pipeline systems inreased marginally. The largest The majority of the more than 190 underground storage sites loated along this orridor are aessible to shippers. At the southwestern terminus of the orridor, more than 30 sites with a working gas apaity of at least 624 billion ubi feet and a daily withdrawal apability of 13 Bf per day are loated within 20 miles of the subjet pipeline systems. Most of this apaity is used by produers, who use it to store short-term exess prodution, and by market enters. Most of the same Southwestern market enters and assoiated storage disussed previously are also used by shippers on this 47 orridor. But, in addition, this orridor links with some of the most ative market enters loated outside the Southwestern prodution area. One of the most signifiant is the Ellisburg-Leidy enter in Pennsylvania, whih provides interonnetions and transportation servies between the pipelines omprising this orridor and the other major interstate pipelines operating primarily within the Northeast States. Shippers using the orridor may also utilize the servies of the CNG/Sabine, Columbia Gas, and New York (Brooklyn Union Gas Company) market enters to expand their marketing and transportation options further. Several expansions have been proposed that ould affet the northwestern portion of this orridor, although they would originate in other areas. For the most part they fous upon expansions that ould tranship some of the vast amount of proposed new Canadian import apaity slated for the Midwest to the Northeast Region (Appendix B, Table B2). For instane, ANR Pipeline Company and Transontinental Storage apaity within eah of the 10 orridors should not be summed 47 to get a U.S. total beause it would result in double ounting.

48 Gas Pipeline Company have proposed the jointly owned Independene projet, whih ould arry 1 Bf per day from ANR s line in northwestern Ohio to a major interonnetion with Transontinental s line in Leidy, Pennsylvania. The new line would also be attrative to Canadian shippers seeking an alternative route to Northeast markets. It ould also provide an alternative route and opportunity for shippers now moving gas from the Southwestern to the Midwestern areas of the ountry to reah ustomers in the Northeast. Other projets that would affet this portion of the orridor and diret some of the new Midwestern pipeline supplies eastward inlude Tennessee Gas Pipeline Company s proposed Eastern Express projet and Duke Energy Corporation s Spetrum projet. These two projets alone represent a total of 1.2 Bf per day of new apaity into the Northeastern United States. The Spetrum projet (0.5 Bf per day) would extend from the Chiago, Illinois, area to New York and New England, mostly by using expanded failities along Duke Energy s affiliated pipelines: Panhandle Eastern, Texas Eastern, and Algonquin Gas Transmission systems (west to east). In addition, an interonnetion with another affiliate, Trunkline Gas Company, ould be upgraded to improve gas supply transshipments from the Southwest Region, if appropriate (as ould the Panhandle Eastern Pipeline system). The Eastern Express projet (0.7 Bf per day) would utilize Midwestern Gas Transmission Company (an affiliate of Tennessee Gas Pipeline Company) to ship supplies southward (or though exhanges of gas) to Tennessee Gas s interonnetion in northern Tennessee and then, through expanded failities on its existing system, transport supplies 48 from the Midwest to the east oast. Southwest-Midwest Corridor has signifiant off-peak apaity The Southwest-to-Midwest orridor extends northward out of East Texas, Louisiana, and Arkansas (Arkoma Basin prodution) and generally through Tennessee/Kentuky into the Midwest Region, although a part of it also travels through Missouri (Figure 12). The prinipal interstate pipeline systems operating along this orridor are: ANR Pipeline Company (ANR), Midwestern Gas Transmission Company (via Tennessee Gas Pipeline Company), Natural Gas Pipeline Company of Ameria (NGPL), Texas Gas Transmission Company (TGT), Texas Eastern Transmission Company 49 (TETCO), and Trunkline Gas Company. These systems represent approximately 7.3 Bf per day, or 29 perent of the total pipeline apaity feeding into the Midwest Region (24.8 Bf per day). They also aount for more than 30 perent of the total pipeline apaity exiting this area of the Southwest. Several of the major pipeline projets that were planned for development between 1991 and 1996, in large part to provide shippers on this orridor greater aess to supplies from the Arkoma Basin in Arkansas/Oklahoma to the Northeast and Midwest markets, were not built. Part of the reason may have been the ompeting plans for Canadian import expansions and the low utilization rates on the existing lines extending to the Midwest Region. Very little underground storage is loated along the midsetion of this orridor. However, shippers have aess to signifiant amounts of storage at either end. This orridor also links together two major gas trading enters: the Henry Hub in Louisiana and the Chiago Center in northern Illinois. In addition, the orridor also inludes several natural gas trading (and prie disovery) loations aessible to shippers and traders via the several major ommerial eletroni trading systems set up in the United States and Canada. During the heating season, these markets are atively used by shippers and other market partiipants as a way to balane their reeipts/deliveries, for arbitrage between the two markets, and to smooth market and prie flutuations through hedging. Pipeline utilization rates on the orridor during peak periods of the heating season are generally in the 90 to 100 perent range, but during the nonheating season, usage rates range between 50 and 70 perent per average day. These figures indiate that a signifiant amount of apaity is available during off-peak periods, even though at the northern end of the orridor there is a large amount of underground storage apaity to refill. At the end of the heating season, for instane, the amount of working gas apaity to be refilled in the three States at the terminus of this orridor Illinois, Indiana, and Kentuky was approximately 287 billion ubi 50 feet (Bf), or the equivalent daily refill requirements of 1.4 Bf per day (210 days in the nonheating season). On this basis, deliveries to storage would need only about 18 perent of the daily pipeline apaity available on this route. 48 In addition, the Eastern Express projet would inlude expansion of Tennessee Gas s pipeline (0.2 Bf per day) between its Niagara, New York, import point and its interonnetions near Leidy, Pennsylvania, and its northern line extending diretly to New England. 49 Mississippi River Gas Transmission Pipeline Company (0.7 Bf per day) also transports gas along this orridor but it terminates in the St Louis, Missouri, area. Its operations in Illinois are onfined to the area east of St Louis. 50 Based on an average 35 perent working gas apaity remaining at the end of Marh 1996 in all sites loated in the three States.

49 In addition, during August 1996 total natural gas onsumption Capaity levels on the Panhandle Eastern Pipeline system did in these three States was only 26 perent as muh as that in not inrease at all. January, the month of highest onsumption. At this level, and assuming that deliveries to these three States were only from Market enters loated in the Waha and Panhandle area of this orridor, apaity requirements would be only about West Texas serve this transportation orridor at its apex. At its 1.9 Bf per day during this off-peak month. Even with the terminus, shippers and traders an link their Texas trading deliveries to storage onsidered, pipeline apaity needed to 51 with the Chiago market enter. In addition, the Midmeet the needs of the area is less than 50 perent of what is ontinent market enter, loated in southentral Kansas, already available. Perhaps beause of this situation, no provides shippers with the opportunity to do business with additional apaity is urrently planned along this orridor. traders in the other two areas. All four pipelines operating in the orridor have diret or indiret links with eah of the market enters. Southwest Panhandle-Midwest Route is a major link between Waha Hub and Chiago This orridor extends from the West Texas and Oklahoma Panhandle areas northward through the major gas prodution fields (Hugoton, Panhandle, et.) loated in southwestern Kansas, and then northeastward toward the Midwest marketplae (Figure 12). Midway on its ourse, in Nebraska, it links with another orridor (see Roky Mountain-Midwest setion) bringing supplies in from the Roky Mountain areas of Wyoming, Utah, and Colorado. There are four major interstate pipelines that run along this orridor: ANR Pipeline Company, Panhandle Eastern Pipeline Company, Northern Natural Gas Company, and Natural Gas Pipeline Company of Ameria. These four pipelines alone onstitute 67 perent of total pipeline apaity exiting this area. These pipeline routes, however, represent only about 17 perent of the total apaity into the Midwest Region. The Trailblazer Pipeline system (average flow of 0.5 Bf per day in 1996) ties in Roky Mountain supplies with an interonnetion to Natural Gas Pipeline Company of Ameria in Nebraska. Several of the pipeline ompanies operating within this orridor have ompleted system expansions sine 1990, although the additions were relatively small in omparison with additions in other orridors. For instane, in 1992, Natural Gas Pipeline Company of Ameria (NGPL) added about 90 MMf per day on the portion of its Amarillo line oming into Illinois and also improved apaity on its system oming out of the prodution areas of West Texas by about 245 MMf per day. In 1996, Northern Natural Gas Company (NNG) ompleted an expansion of 351 MMf per day on its west-to-east route, improving servie in the area and extending north to southern Wisonsin. At its terminus, it also improved its transmission failities and transport apabilities in the Texas and Oklahoma panhandles by 310 MMf per day in 1991 through The ANR Pipeline system inreased apaity by 16 perent in this orridor, although this represented an inrease of only about 83 MMf per day. Traders and transporters using this orridor an also tie their business and trading ativities in with futures market trading. Both the New York Merantile Exhange (NYMEX) and the Kansas City Board of Trade (KCBOT) have operated futures trading markets in the West Texas area for several years. These markets provide traders with the opportunity to hedge 52 their trading ativities and avoid prie volatility risks. Of the two markets, the KCBOT has generated the most interest sine its operational debut in Also, beause of its links to West Texas and the Oklahoma Panhandle area, many (spot market) trading points have beome assoiated with this orridor. Some of the most ative natural gas trading points (on a volume basis) have developed along it. Only a limited amount of underground storage apaity is available to transporters through markets enters loated along this route. Only the Mid-Continent and Chiago market enters offer any appliable aess to storage servies for shippers. However, during the nonheating season a sizeable amount of apaity on these systems is used to transport supplies for injetion into storage failities in Illinois, Indiana, and Mihigan. The ANR Pipeline system in partiular has a number of open-aess sites loated at the northern end of its system in Mihigan. NGPL has a number of storage sites loated in Illinois. Very little expansion along this orridor is planned over the next several years. The only signifiant projets slated for development are the NGPL Amarillo expansion between Iowa and Illinois (110 MMf per day), sheduled for ompletion in 1998, and the Northern Natural Gas Company s East Leg 2000 expansion, whih will inrease servie apaity in its Central and Midwest markets by as muh as 450 MMf per 51, Natural Gas 1996: Issues and Trends, DOE/EIA-0560(96) (Washington, DC, Deember 1996), Chapter The loations of these futures markets in the Waha area of West Texas also enables their servies to be available to shippers operating in East Texas moving supplies through the Texas intrastate system.

50 53 day. The fat that these two projets are foused in the northern tier of this orridor while the southern setion is not slated for signifiant expansion reflets primarily the ripple effet of proposed expansions to Canadian import apabilities. Southwest-Western Westward orridor is overbuilt The Southwest Western orridor is used to transport supplies from the Permian Basin area of West Texas, through New Mexio (where the northern route taps into the San Juan Basin prodution area), and westward primarily to California (Figure 12). Two major interstate pipelines, El Paso Natural Gas Company and Transwestern Pipeline Company, operate along this orridor (Table 8). Both of these pipelines end at the California or Nevada State borders, where they deliver supplies to Southwest Gas Company (Nevada), Southern California Gas Company, and Paifi Gas & Eletri Company, the largest pipelines serving the California marketplae. In addition, Transwestern Gas Pipeline Company links with the Mojave Pipeline Company, an interstate pipeline plaed in servie in 1992 to transport natural gas supplies to the enhaned oil reovery (EOR) and ogeneration ustomers loated in Kern County, California. During the first part of this deade, these two pipeline systems expanded onsiderably: El Paso Natural Gas Company by 19 perent and Transwestern Pipeline by 41 perent. However, these expansions added apaity into California just when it was least needed and, as a result, a ompetitive situation developed between lower-ost Canadian supplies and Southwestern regional prodution. An additional impat was that unused apaity on these systems not only brought about a signifiant drop in load, but in several instanes ustomers atually turned bak ontrated apaity, opting instead to satisfy their needs through the apaity release market. Compared with 1990, when average daily utilization levels on the El Paso and Transwestern systems were above 90 perent, in 1995 average-day utilization levels for the two pipelines were below 60 perent. Indeed, on its system peak day in 1995, El Paso Natural Gas had only a 66-perent load fator overall. Transwestern Pipeline s load fator on its peak day was 60 perent (Appendix A, Table A5). The lower setion of the long-delayed TransColorado pipeline system was ompleted in The southern 25-mile setion of this 266-mile proposed pipeline system is urrently moving about 120 MMf per day from the Ignaio area of the southern Colorado San Juan Basin to the Blano hub in northern New Mexio. While this is less than half of its 53 This expansion will aommodate shippers on the expanded Northern Border Pipeline system. design apability of about 300 MMf per day, when the 54 northern setion of the system is ompleted (proposed late 1998), this reently ompleted setion is expeted to operate at lose to its full apability. Finally, the ompletion of Transwestern Pipeline Company s San Juan Basin expansion (255 MMf per day) in 1996 expanded apaity on the New Mexio side of the San Juan Basin and partially relieved a prodution onstraint situation that has hindered the flow of prodution out of the area for several years. While some of this improved apability will go to the Western marketplae, a major objetive of this projet has been to improve produer aess to ustomers in the U.S. Northeast and Midwest. The Blano (hub) market enter, operated by Transwestern Pipeline Company and loated on the New Mexio portion of the San Juan Basin, has beome a major pooling point for produers in the area and for shippers, espeially those wanting to forward their supplies eastward to the market enters in West Texas (Waha area) and for transhipment on the Northern Natural Gas system (an affiliate of Transwestern), loated to the northeast via the Texas and Oklahoma panhandles (see orridor ). Nevertheless, a signifiant amount of West Texas and New Mexio gas supplies still are transported along this orridor to Arizona, California, and Nevada. In 1996, more than half of the natural gas onsumed in those States (approximately 994 billion ubi feet) was transported via this route. There is very little underground natural gas storage apaity assoiated with this orridor. At the extreme eastern end of the orridor, only one site, the Washington Ranh faility operated by El Paso Natural Gas Company, is reserved primarily for system support servies and is not available for ustomer use. At its western end, in southern California, a limited amount of storage apaity is available to shippers at five sites operated by Southern California Gas Company (SoCal). While about 60 perent of this apaity is reserved for the ompany s own use, shippers an aess what is available, as well as suh storage-related servies as shortterm gas loaning and parking, through the California Energy market enter, whih is also operated by SoCal. Although some of the natural gas injeted into these storage sites omes from produing fields in southern California, a signifiant amount of the working gas stored at these sites 54 The TransColorado Pipeline was originally slated for ompletion in mid but hanging market onditions and other fators delayed onstrution until reently. The northern setion will run from the Big Hole area of Rio Blano County in northwest Colorado to the Ignaio area in southern La Plata County, Colorado.

51 omes out of this orridor. The ombined injetion rate apability of the five sites is 1.1 billion ubi feet (Bf) per day, while their total working gas apaity is 115 Bf. This translates into roughly 104 days needed to fill these sites from srath. But working gas levels at these sites rarely fall below perent, whih means that the equivalent of approximately 83 days per year of about 1 Bf apaity servie on the orridor ould be said to be arried by storage servie operations, or only about 4 perent on an annual basis. Beause of the exess apaity along this orridor, those projets that have been proposed are intended primarily to support expanded servie to the eastern end of this orridor. Nevertheless, the end result of ompleting these projets will be to improve and expand servie to the western end as well. For instane, Transwestern Pipeline Company has proposed further expansion of its San Juan failities by up to 245 MMf per day in 1998, while El Paso Natural Gas Company has submitted plans for a ompression enhanement projet in the same area, whih would improve its apaity by 116 MMf per day. The loation of the failities that are part of these projets, that is, the San Juan Basin triangle, is suh that servie benefits will affet area produers and shippers transporting to either end of the orridor. Canada-Midwest Corridor is major import route for Canadian gas market enter; thus it is strategially loated. It lies along a route that will be expanding to aommodate inreasing amounts of Western Canadian gas being transported to Northeast markets via a southern Canadian/U.S. alternative (see below). A large number of underground storage failities are loated in proximity to several of the pipeline systems operating in this orridor, although not all of them are diretly aessible to shippers. For instane, nine sites (1 Bf per day injetion, 1.8 Bf per day withdrawal apability) are diretly aessible to shippers using the Great Lakes Gas Transmission system, while the storage failities loated in Illinois and operated by Northern Illinois Gas Company (eight sites, 3.4 Bf working gas apaity) are available only through the Chiago Market Center, whih is affiliated with the ompany, or through the 57 ompany itself. Altogether, the daily injetion apability at storage failities linked to the reeiving end of this orridor represents the potential use of about 5 Bf per day of pipeline apaity during the storage refill period from April through Otober. If the proposed development of additional pipeline apaity along this orridor for extension to the Northeast Region is ompleted, shippers will have aess to storage failities and loal distribution ompanies loated in Pennsylvania and New York as well. Indeed, some proposals to expand storage availability in the Northeast to aommodate this apaity growth are already being put on the table. 58 This transportation orridor lies between Western Canadian supply areas and the U.S. Midwest and links two Canadian systems, TransCanada Pipeline Ltd. and Foothills Pipeline Company, with three United States pipeline systems, Great Lakes Gas Transmission Company, Northern Border Pipeline 56 Company and Viking Gas Transmission Company (Figure 13). This tie-in represents about 4.4 Bf per day of pipeline apaity, or about 41 perent of total U.S. natural gas import apaity in Sine 1990, apaity on this route has inreased by more than 40 perent. Also, another pipeline, the Bluewater system, loated at the eastern end of the orridor and plaed in servie in 1995, an transport up to 250 MMf per day on a bi-diretional basis between the United States (Mihigan) and Canada (Ontario). It was developed primarily to support regional storage servies and business at the regional Grand Las natural gas Expansions have ourred on two of the orridor s pipeline systems sine 1990: Great Lakes Gas Transmission (GLT) and Northern Border Pipeline. Capaity on GLT inreased signifiantly, 620 MMf per day or 37 perent sine Inreasing imports, nevertheless, kept this orridor operating at or near apaity during most of the heating season and at about 90 perent on average throughout 1996 (based on annual flow). In 1995, the summer load fator averaged about 72 perent. Currently, GLT atually returns about 68 perent of the gas it imports at Noyes, Minnesota, to Canada via its St. Clair, Mihigan, export point to ustomers in Ontario or transshipment to New York State through Ontario. GLT, with its aess to its underground storage sites loated in Mihigan, an provide its ustomers with a seasonal supply bakup depository and a peaking soure. The Northern Border Pipeline (NBP) system expanded by 0.4 Bf per day, or 39 perent from 1991 through The pipeline is urrently running at or above apaity throughout 55, Form EIA-191, Underground Natural Gas Storage Report. 56 Northern Border urrently serves the Midwest Region with deliveries to 57 The Chiago Center is only indiretly aessible to shippers using this Northern Natural Gas Company and Natural Gas Pipeline Company of orridor. Ameria. The pipeline reeives large amounts of gas from Canada at Monhy 58, Underground Storage of Natural near the Saskathewan and Montana borders. Monhy is the seond largest of Gas in 1997: Existing and Proposed, Natural Gas Monthly, DOE/EIAthe nine entry points for natural gas imports from Canada. 0130(97/09) (Washington, DC, September 1997).

52 most of the year; its lowest monthly daily average load fator in 1995 ran in the neighborhood of 96 perent. Utilization levels on the system urrently are higher than they were in The growth in natural gas demand in Midwestern markets and the ompetitive priing of Canadian natural gas over the past deade spurred most of the expansion ativity that has ourred on this orridor sine However, some of it has also been prodution driven, with Western Canadian produers being the initiators. In fat, most of the expansion projets reently proposed for development over the next several years along this orridor fall into this ategory. The northeastern setion of British Columbia and northern Alberta have developed into enormous gas-produing areas and, as a result, markets are being aggressively sought for this gas, with the United States being the obvious and major target. A very good example of suh a projet is the Alliane projet, whih would bring gas from British Columbia to the Chiago, Illinois, area along the right-of-way of an existing oil pipeline. The projet was initiated by a onsortium of Western Canadian produers dissatisfied with the limited servie offered by the single NOVA(Alberta)-TransCanada system route urrently available to them. If ompleted, the proposed Alliane projet alone would inrease area servie along the 59 orridor by 1.3 Bf per day. Coupled with the extension of 60 the Northern Border Pipeline (in 1998 and 2000) and the Viking Voyageur projet (2000), apaity on this part of the orridor ould inrease by more than 172 perent (3.8 Bf per 61 day) from 1996 levels (2.2 Bf per day). Partly in response to produer demands for additional exit apaity from Alberta and partly beause of the potential ompetition from proposals suh as the Alliane projet, TransCanada has tendered its own expansion plans (1.4 Bf per day) to feed into the proposed Viking Voyageur projet. Several U.S. pipeline ompanies have developed expansion plans of their own that would tie in with TransCanada s additional system expansion plans for 1998 and These projets would also inrease support to shippers wanting to transport gas to Ontario, Canada, via an alternative to the 59 The proposed border-rossing site for the pipeline is slated to be able to move up to 1.6 Bf per day of gas if neessary. 60 In August 1996, the Federal Energy Regulatory Commission approved onstrution of the Northern Border Pipeline Company expansion projet, whih would add 700 MMf per day to import apaity at the Montana border. Correspondingly, Foothill Pipe Line Ltd. of Canada, whih interonnets with Northern Border Pipeline at Monhy, Montana, would expand its eastern leg by the same amount. In February 1997, Foothills Pipeline Ltd., proposed to expand its system further and onduted an open season to gauge shipper demand. 61, Energy Poliy At Transportation Study: Interim Report on Natural Gas Flows and Rates, DOE/EIA-0602 (Washington, DC, Otober 1995), Table 5, p. 32. northern TransCanada route and provide an integral link in support of Columbia Gas Transmission Company s Millennium projet (see next setion). If all of the urrent proposals assoiated with this orridor are atually ompleted, apaity ould inrease by as muh as 4.2 Bf per day over the next several years. This level of inrease is seond only to that proposed for development into the Northeast Region. However, what really distinguishes the growth along this orridor is that the vast majority of new apaity would be on newly built trunklines bringing supplies in from Canada. Canada-Northeast Corridor is target of major expansion proposals The Canada-Northeast orridor links the eastern portion of the TransCanada Pipeline system (and Western Canadian gas prodution) to six pipeline ompanies in the Northeastern United States (Figure 12). The six are: Iroquois Pipeline Company, Granite State Transmission Company, Tennessee Gas Pipeline Company, Empire Pipeline Company, Vermont Gas Company, and St. Lawrene Gas Company. Indiretly, the orridor supplies gas to the National Fuel Gas Supply Company and CNG Transmission Company. The six systems transport gas primarily into New York and the New England States at a total apaity level of 2.4 Bf per day. While the vast majority of the Canadian apaity that omes into the U.S. Northeast is off the northern tier of the TransCanada system, about 5 perent represents apaity that traverses the U.S. Midwest (on the Great Lakes Transmission system), rosses bak into Canada through Ontario, and is imported one again at Niagara, New York. Two of the major pipeline systems along the Canada-to- Northeast orridor were onstruted during the 1990s: the Iroquois (850 MMf per day) and Empire (500 MMf per day) (Figure 10). Both systems serve primarily ustomers in New York State, although the Iroquois system also serves ustomers in Connetiut and Massahusetts (Appendix A, Table A3). These two new lines, plus the smaller North Country Pipeline also added between 1990 and 1996, alone inreased import apaity to the Northeastern United States by nearly 300 perent. In addition, Tennessee Gas Pipeline system more than doubled its import apaity at Niagara, New York, adding 476 MMf per day, or about 129 perent to its 1990 level. The inreasing demand for Canadian gas in the Northeastern United States has been responsible for the very high utilization rates on the systems operating on this orridor. Annual average-day usage rates on these pipelines ran about 85 to 90 perent during During peak periods, the

53 prinipal importing pipeline, Iroquois Gas Transmission Company, was operating about 22 perent above its ertifiated apaity. Even during the summer months, daily apaity utilization levels were in the 90 to 100 perent range. Iroquois often uses line paking on its system to handle heavy demands of shippers. Several natural gas market enters are intriately tied to this orridor. At its western end, five market enters are loated in Alberta, Canada. One of these, the AECO-C hub, is a key trading point on several ommerial eletroni trading systems and is also the point of trade for NYMEX futures ontrats transated for Western Canadian gas. In addition, several U.S. natural gas trading enters are loated at the eastern end of the orridor, suh as the Iroquois, CNG/Sabine, and Ellisburg-Liedy market enters. These enters provide ustomers with interonnetions to at least 10 interstate pipeline systems and 4 intrastate systems serving shippers throughout the Northeast. The availability of suh ative trading enters at both ends of the orridor provides shippers with the transportation tools to transat their business effiiently. Most of the market enters in this orridor offer ustomers aess to underground storage servies, suh as gas loaning, temporary gas parking, and load balaning. In Canada, at the western end of this orridor, approximately 21 Bf per day of daily storage deliverability is available at eight sites. In the U.S. Northeast, storage deliverability of up to 4.6 Bf per day is available to shippers through market enters. In addition, several storage sites loated in Ontario, Canada, are available to shippers transporting supplies to the area via the Great Lakes Transmission system. This orridor is slated to undergo a major expansion over the next several years. If all the urrent expansion proposals were implemented, total diret Canadian import apaity into the U.S. Northeast ould approah 5.0 Bf per day by the end of the entury, a 110-perent inrease over 1997 levels. An already-approved TransCanada Pipeline Ltd. expansion projet, slated for 1998 with further additions being onsidered for 1999 and 2000, would result in expansions at several import points into the U.S. Northeast and development of at least one new import point for Columbia Gas Transmission s Millennium projet. The Millennium projet is projeted to start deliveries in the fall of 1999 to ustomers in the U.S. Northeast. The proposed Vetor Pipeline, whih is a partner with Columbia and TransCanada in the Millennium projet, will tranship supplies through Canada via TransCanada from its St. Clair, Mihigan, export point to the Millennium pipeline at Niagara, New York. Combined with the Millennium import level of 700 MMf per day and several import expansions related to other projets, 62 suh as the Portland Natural Gas Pipeline system, TransCanada s export apaity to the U.S. Northeast ould inrease by 0.9 Bf per day by the end of 1999, a 53-perent inrease over 1996 levels. In onjuntion with TransCanada s multi-year expansion plans, Iroquois Pipeline Company has proposed an expansion of its import apabilities by 160 MMf per day. In addition, several new pipelines have been proposed to move gas supplies being developed off the Canadian Atlanti oast near Sable Island to markets in Canada and the United States. The Maritimes & Northeast pipeline projet is slated to transport gas from the Sable Island Offshore projet. Its route will take it diretly into the State of Maine and through New Hampshire to interonnetions with the Tennessee Gas Pipeline system in Massahusetts. While this northern tier orridor has been the prinipal route used by shippers to import Canadian supplies into the Northeastern United States, the large number of projets reently proposed to bring Canadian supplies into the Midwestern marketplae (see earlier setion) has spurred several major pipeline ompanies to plan large-sale projets that would extend some of this new apaity further eastward to Northeastern markets. If fully implemented, these projets would greatly expand the southern tier orridor, whih in the past has seen only limited use as a route for imported supplies. Canada-Western Demand for Canadian gas has inreased in Western markets The Canada Western route brings natural gas from Alberta and British Columbia, Canada, through the States of Washington, Idaho and Oregon, with terminating points in Nevada and California (Figure 12). While muh of the gas moving on this orridor reahes California at its northern border, some of the supplies also reah California by way of Arizona, being moved south and west via the States of Utah, Wyoming, and Colorado. In Canada, Westoast Gas Transmission Ltd. and Alberta Natural Gas Ltd. (in assoiation with Foothills Pipeline Ltd.) reeive gas from the NOVA Gas Transmission Ltd. (the The Portland Natural Gas Pipeline system (PNGT) (178 MMf per day) 62 will replae and expand upon the Granite State Pipeline Company s 31-MMfper-day import pipeline that brings Canadian natural gas to Maine via Vermont and New Hampshire. The PNGT system may also be supplemented by LNG failities that would be built in Maine.

54 prinipal pipeline system in the region linked into the major prodution areas in Alberta and British Columbia) and transport that gas to the U.S. border (Table 8). There the supplies are reeived by Northwest Pipeline Company (from Westoast Gas Transmission) and PG&E Transmission Northwest (PG&E-NW), formerly Paifi Gas Transmission (PGT) (from Alberta Natural Gas). The two pipelines have a ombined apaity of 3.5 Bf per day, 99 perent of import apaity in the area. This route represents one-third of the total apaity reahing the United States from Canada. While PG&E-NW transports most of its gas (about 82 perent in 1996) diretly southward to California, the Northwest Pipeline system extends south and eastward from its border reeipt point, operating on a bidiretional basis along muh of the eastern setion. At the northern Nevada State line, Northwest Pipeline Company links with the Paiute Pipeline Company, whih until reently was the only gas supplier to the Reno, Nevada, area. Only one new pipeline has been added to the orridor sine 1990, the Tusarora Pipeline Company (113 MMf per day) in This pipeline interonnets with the PG&E NW system at the northern California border and transports gas to the Reno, Nevada, area. Between 1991 and 1996, apaity within this orridor grew by more than 48 perent (1.2 Bf per day at the Canadian border) as apabilities were inreased to meet expeted growth in the regional natural gas market (Table 7). While the downturn in the regional eonomy during the period led to some exess apaity, usage levels for 1996 indiate the trend has turned around slightly, with average utilization levels along some portions of the orridor atually higher than they were in 1990 (Appendix A, Table A6). Shippers using this orridor have aess to the servies of several market enters, although the types of available servies are somewhat limited. For instane, within the California marketplae, the Golden Gate market enter, whih is affiliated with the Paifi Gas and Eletri Company, limits its offerings mainly to parking and loaning servies and interonnetions with six of the prinipal pipeline system loated at the southern end of this orridor. The Sumas market enter, whih operates in the Washington State/Canadian border area, provides shippers, primarily marketers and produers, with a pooling and aggregation point for export trading. At the apex of the orridor are the AECO-C, Alberta, Intra-Alberta and Crossfield hubs. These enters are tied losely to the NOVA pipeline system, whih is the exlusive gas transporter in Alberta. The Intra-Alberta hub, whih is primarily an eletroni trading operation, is linked losely with trading and business onduted at the Sumas market enter. This arrangement allows Alberta produers, shippers, and/or traders to oordinate trading with the pooling and aggregation servies offered at Sumas. Aess to underground storage for shippers along this orridor is limited. Muh of the storage apaity on the southern portion is owned and operated by loal distribution ompanies and is used exlusively to support their own seasonal storage needs. Nevertheless, shippers an aquire aess to storage servies on an as-available basis through some of the market enter operations. The Paifi Gas and Eletri Company, through its Golden Gate market enter, provides limited aess to its three storage sites in northern California (the enter also utilizes PG&E system line paking to support its storage parking and loaning servies). At the Canadian end of the orridor, muh of the available storage is intriately linked with market enter operations, providing parking and loaning servies primarily to produers shipping gas to the United States. These Canadian sites are apable of handling up to 6 Bf per day deliverability and have a working gas apaity level of about 412 Bf. Roky Mountains-Western A new westward orridor was built in 1992 This orridor did not exist until 1992, whih was the year the Kern River Pipeline system was ompleted. This system extends from the Opal, Wyoming, area southwestward through Nevada, just north of Las Vegas, to Kern County, 63 California (Figure 12). Its apaity is approximately 750 million ubi feet per day. The Kern River Pipeline system was developed primarily to arry gas to the enhaned oil reovery market in southern California, whih has been a substantive natural gas market. In 1996 its average day utilization rate was 95 perent, while on its system peak day it operated at 102 perent. In 1997 its servie was extended to the Las Vegas eletri power generation market with the opening of an expanded metering faility with Southwest Gas Company, the major natural gas distributor in the Las Vegas area. Underground storage failities, although available at the apex of this orridor in Wyoming and Utah, do not play a major role in the operations of the Kern River Pipeline system. Although six sites are in the viinity, with a ombined daily deliverability of 0.6 Bf per day and 66 Bf of working gas apaity, only one, Questar Pipeline Company s Clay Basin In California, the Kern River Pipeline system physially merges with the 63 Mojave Pipeline system (400 MMf per day) to form one line serving ustomers primarily in Kern County, California. Mojave reeives its supplies from Transwestern Gas Pipeline Company and El Paso Natural Gas Company at the Arizona-California border.

55 faility (0.4 Bf per day, 51 Bf), is aessible to shippers. Kansas City, Missouri. Currently the new line does not The Western market enter, loated at the upper end of the provide any interonnetions with the two major interstate system, provides ustomers with aess to the Kern River pipelines onneting this orridor to Midwestern markets; Pipeline system and to the Clay Basin site. At the southern rather, its full apaity is ommitted to ustomers loated in end of the orridor shippers have aess to the servies of two the Kansas City area. more natural gas market enters, the California Market Center (operated by Southern California Gas Company/Enerhange Several market enters are available to shippers using this In.) and the Golden Gate Market Center (Paifi Gas & orridor. Loated at the western end is the Western market Eletri Company). enter and at the eastern end the Chiago market enter. The Mid-Continent market enter, loated in southentral Kansas Only one expansion along this orridor has been proposed; and with aess to the Natural Gas Pipeline Company of the Colorado Intrastate Pipeline is assessing the feasibility of Ameria s system, has beome a key natural gas trading expanding its system to serve ustomers in Nevada along a enter for ustomers along this orridor. The market enter in new 360-mile route (250 million ubi feet per day). This line Wyoming urrently has limited business with shippers using would open a new market for new prodution out of the the orridor, primarily beause available apaity is fully Powder River Basin in Wyoming. booked on a long-term basis and shippers have little need for transportation, title transfers/traking, buyer/seller mathing, During the early part of the deade, when the proposed and trade administration servies. It remains to be seen if Altamont Pipeline system was under serious onsideration as planned expansions along this orridor will inrease market a supplier of Canadian gas to California, the Kern River enter ativity, as what apaity is oming in servie is Pipeline Company had a proposal on the table to expand its already fully subsribed. system orrespondingly. However, as a surplus of interstate natural gas pipeline apaity developed in the Western Region Customers using this orridor have a limited number of and the proponents of the Altamont system direted their underground storage failities available for their use. At the target market eastward, those plans were set aside. terminus of the orridor in Wyoming and Colorado are 18 sites that ustomers may aess. Muh of the storage loated Roky Mountains-Midwest at this end, however, is used to support loal produers and distribution ompanies. In the Chiago area orridor, shippers Corridor is expeted to beome more important as transportation apaity expands have aess to storage failities assoiated with the Chiago market enter. This orridor links Roky Mountain natural gas supplies from Utah, Wyoming, and Colorado with markets in the Midwestern United States and with several sizable metropolitan markets in eastern Kansas and Missouri (Figure 13). While the orridor itself does not extend into the Midwest, the several pipelines operating along this route interonnet with major trunklines bringing supplies from the Southwest to Midwestern markets (see ). The Trailblazer System, whih is a ontiguous linkup of the Overthrust, Wyoming Interstate, and Trailblazer pipelines, operates from western Wyoming to eastern Nebraska, where it offloads to the Natural Gas Pipeline Company of Ameria pipeline. The Williams Natural Gas Company and the KN Interstate Pipeline Company also operate along this orridor, but these two pipelines serve primarily loal regional markets (Table 8). In late 1997, the KN Interstate Pipeline Company ompleted its Pony Express Pipeline (255 million ubi feet per day). This line is the first new long-distane line ompleted in this orridor sine the Trailblazer Pipeline was installed during the early 1980's. The line runs from entral Wyoming to south of Compared with most of the other orridors, this partiular one is relatively small. Its importane, however, lies in its future. Currently the Trailblazer system is fully utilized throughout most of the year as the demand for lower pried Roky Mountain supplies grows among Midwestern shippers. In the past, Wyoming and Utah supplies generally moved to a strong southern California gas market, but that market has developed an exess of pipeline apaity during the past several years and is urrently onsidered a soft market for natural gas. With the emphasis on the Western market, development of eastward bound pipeline apaity has been limited in the past. Summary During the past 50 years, the natural gas pipeline network in the United States and Canada has developed into an expansive and highly integrated transmission and distribution system. The 10 major natural gas transportation orridors examined in this hapter reflet only that portion of the network whih involves long-haul operations. At the regional level, many other smaller interstate, intrastate, and loal distribution systems have the responsibility of delivering gas to the

56 ultimate onsumer (see Chapter 4). In addition, there are ould add as muh as 5.0 Bf per day to U.S. import apaity numerous natural gas gathering systems that arry out the task from Canada along these orridors, a 45-perent inrease over of feeding supplies to the long-haul segment of the network levels. This antiipated growth reflets the ontinuing (see Chapter 2). U.S. demand for Canadian natural gas, espeially in the Midwest and Northeast regions, and the desire on the part of Between 1990 and the end of 1997, apaity additions on Western Canadian produers to expand further into these these long-haul orridors totaled more than 12.4 billion ubi markets. feet (Bf) per day, an inrease of about 17 perent. Most of this onstrution entailed expansions to existing mainline While the northern orridors predominate in respet to future systems, although some new, small-to-intermediate-size expansions, it must be kept in mind that a great deal of natural pipelines were also built. The largest ombined inrease in gas produtive apaity is also urrently being developed in new or expansion apaity, 27 perent of the total, ourred the Gulf of Mexio. The logial markets for this natural gas along those orridors transporting supplies from Canada are in the Midwest and Northeast United States, the same (1.2 Bf per day), the Roky Mountains (0.8 Bf per day) and markets slated for the Canadian expansions (as well as the the Southwest (1.0 Bf per day) to the Western Region of the expanding Roky Mountain orridor). Yet, no major United States. On a singular basis, the largest inrease in expansions along the orridors linking the Gulf of Mexio to apaity ourred on the orridor leading from Canada to the these marketplaes have been announed. During the summer Northeastern United States, whih grew by 1.9 Bf per day, months, even with market storage refill supplies using or over 400 perent. signifiant levels of available apaity, a number of the pipelines along these orridors still have signifiant amounts No matter how it is viewed, the orridors with the largest of unused apaity available. This available apaity ould growth in deliverability sine 1990 have been those oming absorb muh of the Gulf s new-found prodution during offinto the United States from Canada. These orridors have also peak periods, but during the heating season when many of maintained the largest sustained utilization rates, with most of these same pipelines are fully utilized, future apaity the pipelines in these orridors operating above 90 perent onstraints ould develop. If deep-water development throughout most of the year. The omparatively lower ost of ontinues over the next deade, most likely some Canadian supplies over the past several years has been a key omplementary onshore expansions would our along these fator in maintaining these high utilization levels. orridors. Based on urrent expansion proposals, the most extensive development of new apaity over the next several years will our along these same orridors, exept for the one direted toward the Western States. At least four new pipelines and several expansions are planned that will expand deliverability not only to the U.S. Midwest and Northeast markets but also to Canadian domesti markets. These projets will improve aess to natural gas supplies in Western Canada and also reate a new orridor that will bring prodution from the developing fields off the oast of Eastern Canada (Sable Island) to Canadian and U.S. markets. These expansions Although there are a few natural gas transportation orridors that are apaity onstrained and/or are operating at lose to full utilization throughout the year, the urrent apabilities of the pipeline network in North Ameria are suffiient to meet the urrent level of demand. And, projet proposals are on the table whih will alleviate those few exeptions where limitations exist. In fat, on the surfae it appears that an exess in pipeline apaity ould develop along several orridors, espeially if antiipated demand does not live up to expetations. The volume inrease would be 37 perent more than the total Canadian 64 import apaity added from 1991 through 1996, 4.3 Bf per day.

57 4. Deliverability to Markets Eah regional market in the United States has widely varying (Table 9). It is the seond oldest region (Table 10) and patterns of energy use and natural gas requirements. has a substantial spaeheating market. Residential and Different regional demographis, weather patterns, and industrial ustomers in the Midwest onsume more distint natural gas ustomer profiles result in different market natural gas as a perentage of total energy (25 perent) needs and onsumption levels. The numerous natural gas than any other regional market exept the major pipeline systems that have evolved over time to provide prodution area of the Southwest (Table 11). transportation servies to and within these end-use markets are designed to aommodate these variations. For instane, Northeast: This region is the most heavily populated and in the older, seasonal markets, regional natural gas is the largest onsumer of energy. Yet natural gas distribution systems are designed to meet spae-heating represents only 21 perent of all energy onsumed, a demands by residential and ommerial ustomers and are omparatively low perentage (Table 11), espeially interlaed with wintertime bakup (underground storage) and sine the region has very old winters. However, natural peaking failities. In less weather-sensitive markets where gas use has inreased at an annual rate of 4.9 perent natural gas demand is mainly for eletri power generation sine Coinidently, this market is a prinipal target and/or industrial usage, storage is needed less for bakup and for Canadian import expansions during the next several more to support some short-term flutuations in demand and years (Appendix B). pipeline transportation system balaning. Southeast: This region has some of the warmest States Exept for those markets in the viinity of major natural gas in the Nation and onsumes the seond smallest amount prodution areas, shippers depend upon major longhaul of natural gas behind the Central Region (Table 11). pipeline systems to provide their link between suppliers and However, almost all of the pipeline systems oming out the regional pipeline network that direts the natural gas to the of the Southwest (Texas and Louisiana) en route to eventual onsumer. The apability of the longhaul trunkline Midwest and Northeast markets travel through the usually reflets the needs of regional grid pipeline Southeast Region. Industrial use of natural gas is the distributors, whih sometimes are other major interstate largest onsuming setor in this region, with 44 perent ompanies but most often are loal distribution ompanies. of the market (Table 12). This hapter disusses natural gas deliverability to end users Southwest: This region not only produes the most in six U.S. geographi market areas: the Central, Midwest, natural gas but also onsumes the most. The industrial Northeast, Southeast, Southwest, and Western regions. The setor s share of the natural gas market is 53 perent, emphasis is upon the apabilities, that is, the apaity and eight times that of the residential (Table 12). Export utilization, of the interstate natural gas pipelines supplying pipeline apaity exeeds inoming by a fator of 12 to natural gas to and within eah region (see Appendix A for a 1, with 16 major interstate pipeline ompanies beginning detailed listing of the pipeline ompanies serving individual in the region (Appendix A, Table A5). Muh of the States). Changes in deliverability sine 1990 and planned deliverability within the market is handled by a large expansions through 2000 are also highlighted. network of intrastate pipeline ompanies. The profile of the ustomer base is addressed to provide some Western: The Western Region is served by the least insight into the urrent operation of pipeline and storage fa- number of interstate pipeline ompanies (seven) and has ilities in the market area. Eah regional market is unique. the least amount of pipeline apaity entering the region, 10.1 million ubi feet per day. However, almost all Central: This market is the largest in area but is the least natural gas oming into the region is onsumed there. populated and produes more natural gas than it The market is a large onsumer of Canadian natural gas. onsumes, despite having the oldest weather (on average) of the regions. As a result, it is a net export market (Figure 13). Most of the apaity entering the region from Canada and the Southwest atually ends in the Midwest market. Major Market Changes, Midwest: More natural gas pipeline apaity enters this market than any other, 24.8 million ubi feet per day From 1990 through 1996, natural gas pipeline deliverability to the major U.S. markets inreased signifiantly. On the interstate pipeline system alone, deliverability inreased by 51

58 Figure 13. Net Natural Gas Pipeline Capaity Entering (-Exiting) Eah Region, Deember ,000 Million Cubi Feet per Day 10, ,000-20,000-30,000-40,000 Midwest Western Northeast Southeast Central Southwest Canada Soure:, EIAGIS-NG Geographi Information System, Natural Gas Pipeline Capaity Database, as of Deember more than 15 perent, or 10.9 billion ubi feet per day 65 of 78 perent, while into the Central Region, rates rose (Table 9), about the same rate as overall growth in natural gas 13 points. The overall rate fell only along routes into the onsumption, 3.0 perent per year (Table 11). This inrease Western and Southwest regions. In some areas of only reflets the growing demand for natural gas and its inreasing limited apaity expansion, the inrease in pipeline usage ontribution to the total national energy onsumption piture. rates reflets a greater use of existing apaity that had Some of the major hanges inlude: been previously underutilized beause of previous overbuilding or a temporary drop in demand. Expansion of pipeline apaity to high demand markets. The largest inrease in interregional apaity Elimination of some previous deliverability during the 6 years was in deliverability to the Western bottleneks. Although average usage rates have Region, 3.2 billion ubi feet per day or 45 perent. inreased, the reported ourrene of market area Seond largest was a 24-perent inrease into the 66 deliverability onstraint is rare. In fat, many of the Northeast Region, or 2.4 billion ubi feet per day apaity additions in reent years have been to improve (Table 9). The development of so muh apaity in the the apability of the regional pipeline systems and their West led to a surplus of apaity and an overall drop in servie to loal markets. In 1997 alone, exluding the the pipeline apaity usage rate, whereas in the exporting Southwest Region, 19 of the 31 ompleted Northeast, demand growth fully supported the inrease. expansion projets affeted servie totally within the In fat, pipelines into the Northeast saw a substantial market area. The Northeast had the highest, with 11 of inrease in average daily usage rates, up 6 perentage 12 projets fitting into this ategory. Currently, apaity points from 1990 levels. Higher pipeline utilization rates. During the period, interregional usage rates inreased by 7 perentage points, reahing a high of 75 perent (on an average day) in Pipeline usage rates within several major market areas also grew signifiantly. For instane, usage rates into the Midwest rose 14 perentage points to an average 65 Based only upon pipelines for whih some flow was reported for a known State-to-State apability. 66 The number and instanes of pipeline servie urtailments have dereased in reent years beause of improved deliverability and system effiienies, but serious system instabilities still our that limit, and sometimes restrit, the free flow of natural gas to ustomers. When system instabilities do our, pipeline operators have the option of exeuting what are known as operational flow orders (see Box, Operational Flow Orders in Chapter 1). 52

59 Table 9. Interregional Pipeline Import Capaity, Average Daily Flows, and Usage Rates, 1990 and 1996 Capaity Average Flow Usage Rate 1 Reeiving Sending (MMf per Day) (MMf per Day) (perent) Region Region Perent Perent Change Change Change Canada Central Midwest 1,211 2, , Total into Region 1,277 2, ,005 1, Mexio Southwest Western Total into Region Central Canada 1,254 1, , Midwest 1,765 2, , Southwest 8,555 8, ,119 4, Western Total into Region 11,824 12, ,230 8, Midwest Canada 2,161 3, ,733 2, Central 8,988 9, ,684 7, Northeast 2,024 2, Southeast 9,645 9, ,134 8, Total into Region 22,818 24, ,265 19, Northeast Canada 467 2, , Midwest 4,584 4, ,474 4, Southeast 4,971 5, ,091 4, Total into Region 10,022 12, ,874 10, Southeast Northeast Southwest 19,801 20, ,613 16, Total into Region 19,901 21, ,676 16, Southwest Central 1,283 2, , Mexio Southeast Total into Region 2,048 2, , Western Canada 2,421 3, ,874 3, Central 365 1, Southwest 4,340 5, ,910 2, Total into Region 7,126 10, ,980 6, Total Within Lower 48 States 73,739 84, ,672 61, Usage Rate shown may not equal the average daily flows divided by apaity beause in some ases no throughput volumes were reported for known border rossings. This apaity was not inluded in the omputation of usage rate. MMf = Million ubi feet. -- = Not appliable. Soures: (EIA). Pipeline Capaity: EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember Average Flow: Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition. Usage Rate: Offie of Oil and Gas, derived from Pipeline Capaity and Average Flow. onstraints appear to be limited mainly to prodution areas, a fat that is refleted in the number of planned expansions through 2000 that address this problem. Larger natural gas share of energy market. On an annual perentage hange basis, the inrease in natural gas onsumption is larger than the growth in total energy use in the United States. The inrease has been espeially notieable in the Northeast market, where natural gas use grew at an annual rate of 4.9 perent while overall energy use inreased at a rate of only 1.2 perent (Table 11). The differene is even more dramati in the Western Region, 53

60 Table 10. Regional Weather and Gas Storage Profile, 1996 Natural Gas Underground Storage LNG Peaking Peak-Day Withdrawal Capability (Deliverability) Supplies Number of Normal Weather Interstate Heating Ranking From From Perent Perent Pipelines Degree Among Working Convent- High- Operated Perent LDC Operating Days States Gas ional Deliverability by Operated Owned Peak-Day in (1960- (1 = Capaity Total Storage Storage Interstate by and Capaity Support Region Region 1990) Coldest) (MMf) (MMf/d) (perent) (perent) Pipeline Independents Operated (MMf) (MMf/d) Central 21 7, ,894 6, , Midwest 17 6, ,130,475 24, ,722 2,685 Northeast 15 6, ,842 11, ,765 3,759 Southeast 18 2, ,717 5, ,044 2,841 Southwest 35 3, ,532 20, , Western 10 4, ,206 7, , U.S. Total ,766,666 74, ,820 11,181 MMf/d = Million ubi feet per day. LDC = Loal distribution ompany. LNG = Liquefied natural gas. -- Not appliable. Soures: Normal Heating Degree Days: U.S. Department of Commere, National Oeani and Atmospheri Administration, State Regional, and National Monthly and Seasonal Heating Degree Days Weighted by Population. Natural Gas Underground Storage: Energy Information Administration (EIA), Form EIA-191, Underground Gas Storage Report. Liquefied Natural Gas: EIAGIS-NG Geographi Information System, LNG Database, as of Deember Table 11. Regional Energy Profile Comparison of Annual Average Change, or Population Overall Energy Consumption Natural Gas Consumption Region As Perent U.S Perent Quantity U.S. Perent of Total Quantity Ranking Perent Estimated Annual 1995 Ranking Annual Energy 1995 (Natural Gas Annual (millions) Change (trillion Btu) 1995 Change Consumed (trillion Btu) Consumption) Change Ratio of Natural Gas Prodution (1996) to Consumption Central 20, , , Midwest 48, , , Northeast 66, , , Southeast 48, , , Southwest 31, , , Western 47, , , U.S. Total 263, , , Not appliable. Soures: Natural Gas Prodution and Consumption: (EIA), Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition. Energy Consumption: EIA, State Energy Data Report, Consumption Estimates (Deember 1997). Population: U.S. Department of Commere, Bureau of the Census. where natural gas use inreased annually by 4.0 perent market fell 2 perentage points between 1990 and 1996, while total energy grew by only 0.3 perent. California with the largest dereases ourring in the Western experiened a 0.4 perent drop per year in overall energy (6 points) and Northeast (5 points) marketplaes prodution during its eonomi slowdown of the early (Table 12), usually heavy markets for eletri power 1990s, a drop that brought down the regional average generation. Atual natural gas onsumption by eletri (Appendix C, Table C2). But as a perentage of total utilities also dereased nationally but only slightly, at an energy onsumption, natural gas still retained its 21- annual average rate of 0.4 perent during the same perent share of the Western regional energy market, the period. The only markets to show a gain in eletri utility same as in onsumption were the Southeast and Midwest regions, 8 and 10 perent per year, respetively. Only in the Derease in natural gas use by eletri utilities. The eletri utility setor s share of the U.S. natural gas 54

61 Table 12. Regional Natural Gas Customer Market Share Changes, (1996 Volumes Consumed -- Billion Cubi Feet) Average Annual Change in 1996 Share of the Natural Gas Market Share Change Sine 1990 Consumption (perent) (perentage point) (perent) Resi- Com- Indus- Eletri 1 Region dential merial trial Utilities Other Resi- Com- Indus- Eletri Resi- Com- Indus- Eletri (Consumption) (vol.) (vol.) (vol.) (vol.) (vol.) dential merial trial Utilities Other dential merial trial Utilities Other 1 1 Central (1,779) (589) (362) (540) (41) (247) Midwest (4,413) (1,782) (899) (1,557) (78) (97) Northeast (3,702) (1,300) (859) (1,131) (300) (112) Southeast (2,377) (476) (331) (1,023) (384) (163) a Southwest (6,715) (443) (307) (3,552) (1,492) (921) Western (2,527) (635) (370) (991) (405) (126) U.S. Total (21,513) (5,225) (3,128) (8,794) (2,700) (1,666) 1 Inludes natural gas used as a vehile fuel, in pipeline and natural gas plant operations, and in assoiation with prodution and gathering failities. a Between plus 0.5 perent and minus 0.5 perent. Note: Totals may not equal sum of omponents beause of independent rounding. Soure:, Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition. Southeast Region did the eletri utility setor inrease 70 ogeneration failities, the industrial setor s share of its share of the natural gas market. the natural gas market inreased to 33, 29, and 28 perent, respetively (Appendix C, Table C3). The Substantial growth in industrial gas onsumption, average use per industrial ustomer inreased the most in 67 espeially for eletriity ogeneration. The industrial the Southwest Region, at an average annual rate of setor s use of natural gas inreased substantially in 16.0 perent (Table 13). Average industrial onsumption 68 several markets, prinipally beause of signifiant per ustomer in the Western and Northeast regions growth in eletriity ogeneration, whih is primarily inreased at an annual rate of 8.4 and 9.7 perent, natural-gas based, and also beause of the relatively low respetively, yet the number of industrial ustomers in 69 natural gas pries in omparison with other fuels. In the these markets atually fell. The number of industrial Northeastern States of New Jersey, New York, and onsumers inreased in the other regions. Massahusetts, whih have a large number of Inreased deliverability from storage. A major inrease in deliverability from underground storage failities sine 1990 has omplemented pipeline expansions in several markets. Sine 1993 alone, daily deliverability from storage inreased by 12 perent, with the largest inrease 67 Natural gas used in ogeneration failities is ategorized and inluded in the industrial setor rather than the eletri utility setor, beause ogeneration represents eletriity generated as a byprodut of industrial/ommerial proesses. ourring in the Southwest, most of it high-deliverability 71 storage. This type of storage is used extensively in the 68 While the number of natural gas industrial ustomers has delined sine 1990 by about 1.0 perent per year, this setor s onsumption of natural gas rose by more than 3 perent per year between 1990 and 1996 as average usage per ustomer rose 5.1 perent per year (Table 13). 70 More than 600 nonutility generating failities are urrently operating in 69 In 1995, nonutilities (ogenerators) aounted for 13 perent of all the Northeast Region, up about 12 perent sine 1992 New York has 183; eletri power generated in the United States, up from 7 perent in In New Jersey, 61; and Massahusetts, , 60 perent of ogenerated power was reated by burning natural gas. 71 See,, U.S. Underground Storage of Derived from, Form EIA-867, Annual Natural Gas in 1997: Existing and Proposed, Natural Gas Monthly, Nonutility Power Produer Report. DOE/EIA-0130(97)/9) (Washington, DC, September 1997). 55

62 Table 13. Regional Natural Gas Customers, Average Annual Change, Residential Customers Commerial Firms Industrial Firms Eletri Utilities Annual Change Annual Change Annual Change 1 Annual Change (perent) (perent) (perent) (perent) In In Number Number Number In In Number In In Number In In of All of Gas- In Total In Gasin Number Average in Number Average in Number Average Type Fired Summer Fired Region 1996 of Users Use 1996 of Users Use 1996 of Users Use Units Units Capaity Capaity Central 5,562, , , Midwest 13,220, ,113, , Northeast 12,829, ,154, , Southeast 5,908, , , Southwest 6,282, , , Western 11,347, , , U.S. Total 55,151, ,704, , Inludes both primary and seondary generating units. Soure: Natural Gas Usage: (EIA), Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition. Eletri Generation Capaity: EIA, Form EIA-860, Annual Eletri Generation Report ( ). region not only to support the swing demands of loal prodution of about 2.3 trillion ubi feet aounted for industrial and eletri utility ustomers but also to approximately 11 perent of the total gas onsumed in the support short-term transportation-balaning needs and 73 Nation. Its exported prodution represented about 2 perent provide inremental peaking supply for ustomers in of the natural gas onsumed elsewhere in the ountry. This distant markets, suh as the Northeast and Midwest. In region had the largest prodution inrease in the Nation the Northeast market, where open-aess interstate between 1990 and trillion ubi feet, or 30 perent. storage deliverability represents 94 perent of all available, several of the largest proposed pipeline The region is the largest in area and the least populated. The expansion projets inlude improved aess to existing total volume of gas onsumed in the region in 1996, storage sites and expansion of their deliverability 1.8 billion ubi feet, was also the least onsumed in the six (Table 10). regions. Muh of this gas is onsumed for spae heating, as it has the seond highest perentage of households using natural gas. Regional Overviews The natural gas pipeline apaity profile of eah region in the ountry has evolved over time to meet its partiular requirements. Eah region differs in limate, underground storage apaity, number of pipeline ompanies, and availability of loal prodution. Additionally, the varying demographis of eah region ditate different patterns of gas use and potential for growth. The region s old winters, ombined with the lowest residential pries for natural gas of any region, help make the residential setor a very large onsumer of natural gas. The residential setor aounted for 33 perent of all natural gas onsumed in the region in 1996 (Table 12). Plentiful supplies from prodution and storage sites within the region and adequate apaity on loal transmission and distribution lines ensure that peak demands of residential ustomers are met during the winter. Central Regional Market The Central Region produes more gas than it onsumes and 72 therefore is a net exporter of natural gas. Its 1996 natural gas The industrial setor is also a large onsumer of natural gas (30 perent), while natural gas use for eletri power generation in the region onstitutes only 2 perent of natural gas usage, one of the lowest rates among the six regions. Beause it is a major produer of natural gas, almost 14 perent of gas onsumption in the region in 1996 was 72 Still, 4 of the 10 States in the region, Iowa, Missouri, Nebraska, and South Dakota, are almost totally dependent on the interstate pipeline network 73 See,, Natural Gas Annual 1996, for their supplies of natural gas (Appendix C, Table C2). DOE/EIA-0131 (Washington, DC, September 1997) and previous editions. 56

63 devoted to natural gas prodution and transportation-related ativities (Table 12). Although it is not as highly populated as the other regions, the Central Region has several large metropolitan markets, whih are major ustomers of the interstate pipeline network. To name the largest: Denver, Colorado; Salt Lake City, Utah; Kansas City, Kansas and Missouri; and St. Louis, Missouri. Large underground natural gas storage failities are loated in proximity to these areas The loal distribution ompanies (LDCs) serving these markets aount for about 16 perent of the total storage deliverability in the region (Table 10). LNG peaking supplies are found only in Iowa and Nebraska, two States with limited underground storage apaity and no loal prodution apabilities (Appendix C, Table C1). Entering/Exiting Capaity In 1996, approximately 12.8 billion ubi feet (Bf) per day of pipeline apaity entered the Central Region (Figure 14), 8 perent above the 1990 level (Table 9). Only about 10 perent of that apaity was destined for markets within the region. Twelve pipeline systems enter the region from the south and east, while four enter from the north arrying Canadian supplies (Appendix A, Figure A1). The average utilization rates for pipelines transporting Canadian gas tend to be higher than those arrying domesti supply, 99 perent versus about 60 perent from the Southwest and 94 perent from the Midwest (Table 9). Nevertheless, beause of an inrease in regional prodution and in natural gas demand in both the Midwest and Central regions during the past 5 years, apaity usage on lines transporting domesti supply from the south and east also inreased substantially, about 10 perentage points sine Another fator in the inreased pipeline usage rates has been the more effiient use of apaity during off-peak periods via the apaity release market. Most of the apaity exiting the region (52 perent) flows to Illinois in the Midwest Region, with the pipeline systems involved operating at average utilization rates of 83 perent in 1996 (Appendix A, Table A1). Sine 1993, Central Region supplies have also flowed into the Western Region to serve markets in California and Nevada, with the pipelines serving these markets operating at average utilization rates of nearly 95 perent. Deliverability Within the Region Eight of the interstate pipeline ompanies traversing the Central Region also have major servie ommitments within the region (Figure 14), aounting for 80 perent of their peak-day deliveries. In 1996, these pipeline systems operated at an average utilization rate of about 80 perent, delivering 10.3 Bf on their individual system peak days at 1,742 delivery and/or pipeline interonnet points. In addition, a number of intrastate pipeline ompanies provide deliveries and/or interonnetions with the interstate system 74 to support loal markets. The largest servie ommitments of the interstate pipeline ompanies are for deliveries to other interstate pipelines within the region rather than to LDCs. For instane, Northern Border Pipeline Company delivers more than two-thirds of its shipped volumes to other interstate pipeline ompanies, while the rest is delivered to small ustomers in the region. Of the regional interstate pipeline ompanies, the largest State-to-State apaity is 972 million ubi feet per day on Williams Natural Gas Company's line from Kansas to Missouri (Appendix A, Table A1). However, the average usage rate on this and similar servie lines in the area is low, primarily beause of the seasonal nature of the servie; low summertime flows tend to offset the high winter flows. In 1996, for instane, apaity utilization on Williams line from Kansas to Missouri was only 27 perent. Of all the interstate pipeline ompanies serving the region, Northern Natural Gas Company has the largest State-to-State pipeline apaity, 2.1 Bf per day from Kansas to Nebraska. Kansas Power & Light Company is the largest LDC in the region and the 13th largest LDC, in terms of sales, in the United States. It serves primarily the Kansas City, Missouri, area and has demands on interstate pipeline apaity of up to 1.5 Bf per day, mostly supplied by Williams Natural Gas Company. Kansas Power & Light also aounts for two-thirds of the reserved apaity on the interstate system in Kansas and one-third of the total in Missouri. A major LDC in the western part of this region is Mountain Fuel Supply Company, whih serves the Salt Lake City area and aounts for 99 perent of the total shipments on interstate natural gas pipelines operating in Utah. Questar Pipeline Company, an affiliate, supplies the needs of this distribution ompany. The Publi Servie Company of Colorado is the major distributor of gas in Colorado, with more single-state end-use ustomers than any other ompany in the region. Colorado Interstate Gas Company provides nearly all of the gas to this LDC. Storage Deliverability Underground natural gas storage in the Central Region is notable for several reasons. First, most of the storage failities are used to store exess prodution rather than to serve as a supply soure for loal markets. Seond, the region has the, Form EIA-176, Annual Report of 74 Natural and Supplemental Gas Supply and Disposition. 57

64 Figure 14. Interstate Natural Gas Capaity Summary for the Central Region, 1996 (Volumes in Million Cubi Feet per Day) ID Canada 1,563 1,563 Estimated Total Throughput Capaity Entering: 12,824 Leaving: 13,253 Montana 66 1, North Dakota 1,729 MN 84 Western Region 1, , South Dakota 1,575 Wyoming 26 WI NV 620 2,354 1, , , ,625 Iowa IL Nebraska 2,953 Midwest Region Utah Colorado , ,005 3,901 Kansas 1, AZ 2,531 Missouri NM OK KY 2, ,272 AR 2,814 TN Southwest Region 8,609 Prinipal Interstate Natural Gas Pipeline Companies Operating in the Central Region Regional Servie Level Systemwide Utilization Rates 1 % Primary/ Perent of Number Number Regional Seondary System of of Supply System Peak-day Delivery Interon- 12-Month Peak Summer Pipeline Name Soure(s) 2 Configuration 3 Deliveries Points nets 4 Average 5 Day 6 Offpeak Regional Pipelines Colorado Interstate Gas Co CE, SW Trunk/Grid KN Interstate Gas Co CE, SW Trunk/Grid Mississippi River Transmission Corp. SW Trunk/Grid Northern Border Pipeline Co Canada Trunk Northern Natural Gas Co SW Trunk/Grid Questar Pipeline Co CE Grid/Trunk Trailblazer Pipeline Co CE Trunk Williams Natural Gas Co SW, CE Grid Williston Basin Interstate PL Co CE Grid/Trunk Wyoming Interstate Gas Co CE Trunk Supplemental Pipeline Servie ANR Pipeline Co SW Trunk/Grid Kern River Gas Transmission Co CE Trunk Natural Gas Pipeline Co of Ameria CE, SW Trunk/Grid Noram Gas Transmission Co SW Grid/Trunk Northwest Pipeline Co Canada Trunk/Grid Panhandle Eastern Pipeline Co SW Trunk Texas Eastern Transmission Co SW Trunk Viking Gas Transmission Co Canada Trunk Usage rates are based upon apaity and transportation volumes for the whole system and do not represent regional servie only. 2 "Trunk systems are long-distane trunklines that generally tie supply areas to market areas. Grid systems are usually a network of many interonnetions and delivery points that operate in and serve major market areas. Some systems are a ombination of the two. 3 Represents the perent of total pipeline system volume delivered within the region on the system peak-day ourring in the heating year. 4 Represents total system apaity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 5 Represents total system apaity divided by the single peak-day volumes delivered in the heating year as reported in FERC Form 2. 6 Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based on FERC Form 11 gas delivery data for 1995) divided by 153 days. April and Otober are onsidered to be months that shoulder the heating season of November-Marh. Soures: Capaity: Federal Energy Regulatory Commission, FERC 567 Capaity Report, System Flow Diagram and Annual Capaity Report (18 CFR );, EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity, as of Deember Delivery and Transport Volumes: Federal Energy Regulatory Commission, FERC Form 11, Natural Gas Pipeline Company Monthly Statement and FERC Form 2, Annual Report of Major Natural Gas Companies. 58

65 Nation's largest storage site, the Baker/Cedar Creek Field in In all States in the region, the number of residential and Montana, with a working gas apaity of 164 Bf. However, ommerial ustomers inreased, whereas in three States the the total regional working gas storage apaity number of industrial ustomers dropped by more than (approximately 566 Bf) is only 15 perent of the U.S. total 6 perent per year (Appendix C, Table C4). Yet, the average (Table 10), while daily deliverability from storage is only use by industrial ustomers inreased at an annual rate of 6 Bf per day, or 8 perent of the U.S. total. 3.2 perent and total use inreased at an annual rate of 4.6 perent (Table 12). Refleting this, the industrial setor s Storage failities in Kansas provide a major servie to the share of the regional market inreased from 28 perent in interstate pipeline systems that move natural gas to the 1990 to 30 perent in Midwest Region, but they are also integral to regional requirements. For example, about 35 perent of the State's working Natural gas use still remains only a very small perentage of gas storage apaity of approximately 109 Bf is owned and the total energy used for eletriity generation. While the operated by Williams Natural Gas Company, whih is installation of gas-fired generating apaity at utilities within primarily a regional pipeline system. About 96 perent of the the region inreased at an annual rate of 1.2 perent during State's storage apaity is available to ustomers and shippers the first part of the deade, its share of the natural gas market on other interstate trunklines, while the remaining 4 perent fell 1 perentage point and atual onsumption fell by is devoted to loal distribution and prodution field servie 4.3 perent per year (Table 12). One reason is that utilities in (Appendix C, Table C1). About 41 perent of the daily peak- this region depend primarily on oal, whih is generally day storage deliverability in the State, or 960 million ubi available at a relatively low ost. However, loal environfeet per day, is available to the two interstate pipeline mental needs, linked with tehnologial onstraints, ould ompanies traversing the region, Northern Natural Gas and have an impat on future development planning. Montana, Panhandle Eastern Pipe Line Company. North Dakota, and Utah have some of the major oal basins in the United States. Storage failities in the rest of the region serve primarily as seasonal supply soures for loal markets. Storage fields in Although the industrial setor has gained a larger share of Utah provide servie to shippers using the Questar Pipeline overall natural gas use in the region, the residential setor still system as well as to the Salt Lake City area. The storage fields represents the major share of gas use. The overall growth of in Colorado and portions of Wyoming serve the Denver area natural gas onsumption in the region, about 3.8 perent through the Colorado Interstate Gas Company system. annually from 1990 through 1995, along with the growth in regional pipeline average utilization rates, from 57 perent in End-Use Consumption 1990 to 70 perent in 1996 (Table 9), would seem to indiate the need for some expansion in the near future. There are signs that some ations are already being taken in this regard. Within the region, natural gas has gained a slightly larger share of the energy marketplae sine 1990, rising 1 perentage point to 24 perent (Table 11). Consumption Reent and Proposed Expansions inreased at an annual rate of 3.8 perent from 1990 through 1996, while total energy prodution rose at a 2.1 perent rate. In 1997, eight pipeline expansion projets were ompleted in In every State in the region, natural gas experiened a growth in market share, with North and South Dakota and Utah 75 having the largest inrease. In eah of these States, aess to greater loal prodution was a major ontributing fator. Also, the ratio of State prodution to onsumption at least doubled in eah State ompared with that in 1990 (Appendix C, Table C2). Greater onsumption of loal 76 supplies was supported in part by low pries brought on by an inability by produers to ship their gas elsewhere beause of apaity limitations on several of the longhaul trunklines exiting the region. 75, Capaity and Servie on the Interstate Natural Gas Pipeline System, 1990: Profiles and Analyses, DOE/EIA-0556 (Washington, DC, June 1992), Table 16, p , Natural Gas 1996: Issues and Trends, DOE/EIA-0560(96) (Washington, DC, Deember 1996), Chapter 5. the Central Region, the largest of whih was the new Pony Express line owned and operated by KN Interstate Pipeline Company (Appendix B, Table B1). The new line runs from southern Wyoming to the Kansas City, Missouri, area and helps alleviate some of the apaity restraint problems experiened by Roky Mountain produers in reent years. Also ompleted were the Trailblazer system expansion and several area expansions by Colorado Interstate Pipeline Company that addressed the same onstraint problems and expanded the flow of area gas toward the Midwest. While ompletion of these projets helped resolve some prodution-side demands for apaity, onsumer demands in the area have spurred several additional expansion proposals (Appendix B, Table B2). Growth in the Denver, Colorado, metropolitan area, for instane, has generated similar proposals from two of the area s largest systems: KN 59

66 Interstate Pipeline Company and Publi Servie Company of pipelines (Crossroads and Bluewater) were onstruted in the Colorado. The proposals all for developing new lines and region (Figure 10, Chapter 3), and a number of expansion expanding old ones to bring expanding northern Wyoming projets were ompleted. The primary expansions inluded gas prodution to the Denver area. The prinipal question is additions to the Great Lakes Transmission System (a 41- whether both projets, as urrently designed, will be perent inrease in apaity), the Northern Border Pipeline ompetitive and nondupliative enough to be built. (36 perent), and ANR Pipeline Company (18 perent in Mihigan and Indiana). Midwestern Regional Market The Midwest Region is the Nation's seond largest market for natural gas and is served by an extensive regional pipeline network (Table 11). The region is weather-sensitive, with old winters and moderate summers. Minnesota and Wisonsin are among the oldest States in the Nation, while the other four States in the region are older than the national average (Table 10). The region also has a number of major population enters and is the third largest of the six regions in population. The large number of residential spae-heating ustomers, ombined with the old winters, result in large residential requirements for natural gas. Yet, the region s geographi position between the Central and Northeast regions has resulted in a signifiant portion of the region s pipeline system apabilities being reserved for deliveries beyond its borders. The region s two northernmost States, Wisonsin and Minnesota, as well as portions of Mihigan, are served by pipelines importing Canadian supplies, while the southern portion of the region is served primarily by major trunklines oming from the Southwest. Regional prodution, prinipally from Ohio and Mihigan, provides a little more than 8 perent of the gas onsumed in the region (Table 11). The Midwest Region also has the largest amount of underground storage apaity and daily deliverability from storage of any region, more than 30 perent eah of the U.S. total. Regional LDCs ontrol about 61 perent of daily deliverability, more than any region but the Western. Entering/Exiting Capaity Today 18 interstate pipeline ompanies have the apaity to move 24.8 Bf of gas into the Midwest per day (Appendix A, Table A2). The total apaity of the interstate pipeline ompanies entering the region is more than for any other region. Of that amount, 35 perent enters through Illinois, 26 perent through Ohio, 23 perent through Minnesota, and the remainder through Indiana (Figure 15). Capaity additions into the Midwest Region from 1991 through 1996 totaled 2.0 Bf per day, an inrease of 9 perent over 1990 levels (Table 9). Two new major interstate Regional peak-day deliveries by the interstate pipelines on behalf of shippers approximated 19.8 Bf per day during the heating season, whih is equivalent to about 80 perent of the apaity into the region (Figure 15). When deliveries to other interonneting interstate pipelines are inluded, the peak-day total is equivalent to 99 perent of apaity. Although some demand is satisfied through intraregional prodution and deliveries, the vast majority of natural gas servie in the region is dependent on the interstate system. In 1996, utilization of total apaity entering the region was 78 perent (Table 9), the seond highest of the gas-importing regions. This is a dramati hange from 1990, when the utilization rate was the seond lowest. Natural Gas Pipeline Company of Ameria has about 14 perent of the total throughput apaity into the Midwest, primarily with onnetions into Illinois (Appendix A, Table A2). Other major players are: Texas Eastern Transmission Corporation with 10 perent, and ANR Pipeline Company and Trunkline Pipeline Company with 8 perent eah. Texas Eastern Transmission Corporation moves most of its gas through to markets in the Northeast. On the other hand, almost all of the ontrat ommitments of the other ompanies represent ommitments for deliveries within the Midwest market only. On pipelines entering the region from Canada, the average daily utilization rate in 1996 was 85 perent (Table 9). Average utilization levels on lines entering from the Southeast Region (into Illinois, Indiana, and Ohio) and from the Central Region (into Minnesota and Illinois) were somewhat lower: 82 perent and 78 perent, respetively. Many of the pipelines with the highest utilization rates into the Midwest from the Southeast Region are heavily involved in transporting gas to the Northeast Region or to storage sites during the nonheating season and for meeting system-load balaning need. Deliverability Within the Region Nine of the interstate pipeline ompanies entering the Midwest terminate and deliver most of their gas for shippers within the region (Figure 15). For instane, ANR Pipeline Company operates in all States in the region exept Minnesota and an import 2.0 Bf per day into the region. In 1996, it had a systemwide average flow rate of about 70 perent. But the largest regional pipeline is Natural Gas 60

67 Figure 15. Interstate Natural Gas Capaity Summary for the Midwest Region, 1996 (Volumes in Million Cubi Feet per Day) 2,799 ND ,049 SD 1,655 2,679 1, , Canada 2,543 9,879 1,370 2,354 Central Region Entering: 24,787 Leaving: 9,784 2,953 IA MO 3,901 Estimated Total Throughput Capaity 550 1,708 4,568 1,417 2,209 4, ,944 3,560 1,799 KY 2,480 1,792 2,135 2, ,462 1,573 WV PA 465 9,821 Southeast Region 4,887 2,038 Northeast Region Prinipal Interstate Natural Gas Pipeline Companies Operating in the Midwest Region Regional Servie Level Systemwide Utilization Rates 1 % Primary/ Perent of Number Number Regional Seondary System of of Prinipal Market Region / Supply System Peak-day Delivery Interon- 12-Month Peak Summer Pipeline Name Soure(s) 2 Configuration 3 Deliveries Points nets 4 Average 5 Day 6 Offpeak Regional Pipelines ANR Pipeline Co SW Trunk Crossroads Pipeline Co SW Trunk 100 NA 1 NA NA NA Great Lakes Gas Transmission Co Canada Trunk Midwestern Gas Transmissions Co SW Trunk Natural Gas Pipeline Co of Ameria SW Trunk Panhandle Eastern Pipeline Co SW Trunk Texas Gas Transmission Corp SW Trunk Trunkline Gas Co SW Trunk Viking Gas Transmission Co Canada Trunk Supplemental Pipeline Servie Columbia Gas Transmission Corp SW, NE Grid CNG Transmission Corp SW, NE Grid Mississippi River Transmission Co SW Trunk Northern Natural Gas Co SW, Canada Trunk/Grid Tennessee Gas Pipeline Co SW Trunk Texas Eastern Transmission Co SW Trunk Usage rates are based upon apaity and transportation volumes for the whole system and do not represent regional servie only. 2 "Trunk systems are long-distane trunklines that generally tie supply areas to market areas. Grid systems are usually a network of many interonnetions and delivery points that operate in and serve major market areas. Some systems are a ombination of the two. 3 Represents the perent of total pipeline system volume delivered within the region on the system peak-day ourring in the heating year. 4 Represents total system apaity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 5 Represents total system apaity divided by the single peak-day volumes delivered in the heating year as reported in FERC Form 2. 6 Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based on FERC Form 11 gas delivery data for 1995) divided by 153 days. April and Otober are onsidered to be months that shoulder the heating season of November-Marh. NA = Not available. Soures: Capaity: Federal Energy Regulatory Commission, FERC 567 Capaity Report, System Flow Diagram and Annual Capaity Report (18 CFR );, EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity, as of Deember Delivery and Transport Volumes: Federal Energy Regulatory Commission, FERC Form 11, Natural Gas Pipeline Company Monthly Statement and FERC Form 2, Annual Report of Major Natural Gas Companies. 61

68 Pipeline Company of Ameria, with 3.3 Bf per day. In 1996, Mihigan and Illinois have the largest number of gas storage its average daily usage rate within the region was 84 perent. failities in the region. Their ombined working gas storage However, Natural Gas Pipeline Company of Ameria is apaity in 1996 was approximately 0.9 trillion ubi feet, or seond to ANR Pipeline in the amount of regional peak 78 perent of the total regional storage apaity (Appendix C, deliveries (almost all in Illinois). Table C1). This represents a peak-day deliverability rate of 18 Bf, or 77 perent of the area's apability. In Illinois, Those pipeline systems involved in extensive trade with 71 perent of the daily deliverability from storage is held by Canada had some of the highest systemwide average flow three large LDCs: Northern Illinois Gas Company, Illinois rates in the region (Appendix A, Table A2). In 1996, the Power Company, and Central Illinois Publi Servie average flow rates for both the Great Lakes Gas Transmission Company. Northern Illinois Gas Company also uses part of its and the Viking Transmission pipelines were 94 perent. working gas storage (the exess) to support shippers using its Chiago market enter. In ontrast to utilization rates on lines entering the region or moving gas to the Northeast, intraregional utilization rates Great Lakes Gas Transmission and ANR Pipeline ompanies averaged only 53 perent in This is the ombined use Mihigan storage failities extensively to support their average utilization of all flows from one State within the shippers needs. In the first ase, the Great Lakes system region to another. This statisti, ombined with the generally transports most of its volumes eventually to markets in low systemwide flow rates for the pipelines serving the Ontario, Canada, but uses Mihigan storage sites to store Midwest in 1990, seems to indiate that most pipeline supplies shipped for Canadian ustomers during the ompanies have suffiient throughput apaity to summer for redelivery during winter peak periods. ANR aommodate any additional demand for natural gas in the provides essentially the same servie but for domesti near term. shippers who need to supply ustomers throughout the Midwest during peak periods. These ativities help maintain A relatively few large shippers aount for the bulk of the gas high load fators on these systems during the summer months. delivered by interstate pipeline ompanies within the region. In Illinois and Ohio, the demands of the two largest LDCs Beause of the region s relatively old and volatile weather, represent 47 and 55 perent, respetively, of the total LDCs in this market also have ome to rely on LNG peaking interstate system volumes delivered in eah State and the failities to supplement or substitute for unavailable loal equivalent of 25 and 30 perent, respetively, of the total underground storage apaity. The Midwest is the third 77 apaity entering those States. largest soure of LNG storage, with about 18 Bf of storage apaity and 2.7 Bf of peak-day deliverability. In Illinois and Indiana, the largest LDCs eah interonnet with at least three major pipeline systems, providing End-Use Consumption flexibility in their purhase and transportation strategies. On the other hand, in Minnesota, the major LDCs aquire gas Natural gas usage aounts for about 25 perent of overall from only one interstate pipeline ompany, Northern Natural energy onsumption in the Midwest, whih is seond only to Gas. the 39 perent level in the Southwest Region, the major U.S. prodution area (Table 11). Sine 1990, the natural gas share Storage Deliverability in the region inreased by 1 perent. The levels in the individual States of the region range from 21 perent to as The Midwest has the highest level of working gas storage high as 31 perent of overall onsumption (Appendix C, apaity of any region, 1.1 trillion ubi feet (Table 10). Table C2). During the heating season, storage withdrawals in this region averaged 2.0 Bf per day, with muh greater levels Natural gas onsumption in the region inreased at an annual on peak days (approximately 3.8 Bf). 77 Derived from data reported to the on Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition, and the EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity, as of Deember , Form EIA-191, Monthly Underground Gas Storage Report. 78 rate of 2.9 perent from 1990 through All ustomer setors showed an inrease, but a major ontributor to this gain has been the growth in the use of natural gas by eletri utilities within the region (Table 12). Although eletri utilities aount for only 2 perent of regional natural gas onsumption, the amount of eletri generating apaity fired by natural gas grew at an annual rate of 8 perent, while the number of gas-fired units inreased at an annual rate of 0.3 perent during the period (Table 13). 62

69 Although the region's population base grew by only 3 perent during the 1980s (the smallest inrease of the six regions) and 1.2 perent annually in the early 1990s (Table 11), residential onsumption of natural gas in the region inreased at an annual rate of 3.7 perent between 1990 and This growth was seond only to the inrease in this setor in the Southeast Region (Table 12). The old winters in the Midwest aount for the residential setor using 40 perent of the natural gas delivered to the region eah year (up 1 perentage point sine 1990). The number of residential ustomers in the region inreased during the period as did the average use per ustomer (Table 13). Industrial setor onsumption inreased at a 3.4 perent annual rate as well, although its share of the regional natural gas market fell slightly (Table 12). There had been some speulation that industrial gas demand in the Midwest would derease beause of a trend toward greater servie industry development, displaing heavy industries that tend to be greater users of natural gas, but the average use per industrial ustomer atually inreased at an annual rate of 2.6 perent. The number of industrial ustomers grew slightly during the period. Reent market patterns suggest that natural gas demand in the Midwest will ontinue to inrease into the next entury but probably at a slower rate than demand growth in some of the regions. Although major plans are underway to inrease deliverability to the Chiago market area, it is likely that muh of that apaity will be forwarded to the Northeast. Reent and Proposed Expansions Three pipeline expansion projets into the Midwest Region were ompleted during 1997, providing 441 million ubi feet per day of additional interstate servie (Appendix B). Only one of these projets, the ANR Mihigan Leg expansion, affeted the major Chiago market. The other two provide additional servie to growing markets in Wisonsin and Minnesota. Several large new pipelines and major expansion projets into the region have been proposed, primarily to transport Canadian natural gas from expanding prodution fields in Alberta and British Columbia to the Chiago area. What is noteworthy about this effort is that the ultimate market for muh of this new apaity will be beyond the region, in eastern Canada and the U.S. Northeast. Indeed, if these projets were targeted only toward gaining market share within the Midwest Region, an exess of apaity would develop over the next several years. Planned apaity expansion from the Southwest, whih remains the largest soure of Midwest market gas supply, is minimal. Northeast Regional Market The Northeast onsumes more energy than any other region, although only 21 perent (up 3 perent sine 1990) is in the form of natural gas (Table 11). It is the most heavily and densely populated of the six regions. At one time, the Northeast was a major soure of natural gas and, as a result, a large distribution network of pipelines has been in plae for many years. Similarly, the region has onsiderable aess to underground storage sine gas storage fields were first developed and used ommerially in the area. Still, the New England States have only truly had aess to natural gas supplies sine the 1950s. The region has large swings in gas demand beause of weather. Overall, it is the third oldest of the regions (Table 10), with some of the oldest States in the Nation at its northern limits. Withdrawals from storage are neessary to meet peak demand, as total apaity entering the region plus regional gas prodution are only about two-thirds of the region's peak demand. Residential and ommerial natural gas onsumption (mostly spae-heating demand) aounts for the largest share of the regional natural gas market although the industrial and eletri utility setors also represent large users of natural gas, with 31 and 8 perent, respetively (Table 12). The major markets in the region are the metropolitan areas of Boston, Massahusetts; New York City; Philadelphia/Trenton; Baltimore/Washington; Rihmond, Virginia; and the orridor from Erie, Pennsylvania, to Buffalo, New York. Entering/Exiting Capaity Today the interstate pipeline ompanies serving the Northeast have aess to supplies from all major domesti gas-produing areas and from Canada. The two main flows of gas into the region are from the Southeast into Virginia and West Virginia, and from the Midwest into West Virginia and Pennsylvania (Figure 16). Muh of this apaity moves within the region toward New York City and Boston. In 1996, the interstate pipeline system had the apaity to move approximately 5 Bf per day along routes oming out of both the Southeast and Midwest regions. In addition, limited amounts of liquefied natural gas (LNG) is imported into Massahusetts from the Middle East. Transportation apaity into the Northeast inreased by more than 2.4 Bf per day (24 perent) between 1990 and 1996 (Table 9), seond only to the inrease in the Western Region. Most of this new apaity provided greater aess to Canadian supplies. Some of the larger projets inluded ompletion of the Empire Pipeline (0.5 Bf per day), whih 63

70 Figure 16. Interstate Natural Gas Capaity Summary for the Northeast Region, 1996 (Volumes in Million Cubi Feet per Day) Estimated Total Throughput Capaity Entering: 12,429 Leaving: 2,558 4,887 Midwest Region 2,038 2,730 5,981 OH Pennsylvania , , ,589 2,752 West 21 Virginia 3,213 2, Virginia 1, KY TN 26 NC Canada 2,393 2, , New York 1,059 1,571 Vermont Massahusetts Rhode Island Connetiut 2,975 1,900 New Jersey Maine 31 Maryland Delaware Southeast Region New Hampshire 5,149 Prinipal Interstate Natural Gas Pipeline Companies Operating in the Northeast Region Regional Servie Level Systemwide Utilization Rates 1 % Primary/ Perent of Number Number Regional Seondary System of of Prinipal Market Region / Supply System Peak-day Delivery Interon- 12-Month Peak Summer Pipeline Name Soure(s) 2 Configuration 3 Deliveries Points nets 4 Average 5 Day 6 Offpeak Regional Pipelines Algonquin Gas Transmission Co SW Trunk/Grid CNG Transmission Corp SW, NE Grid Columbia Gas Transmission Co SW, NE Grid Eastern Shore Natural Gas Co SW Grid/Trunk 100 NA NA NA NA NA Equitrans In SW, NE Grid Granite State Gas Transmission Co Canada Grid/Trunk 100 NA NA NA NA NA Iroquois Gas Transmission Co Canada Trunk National Fuel Gas Supply Corp SW, Canada Grid/Trunk Tennessee Gas Pipeline Co SW, Canada Trunk Texas Eastern Transmission Corp SW Trunk Transontinental Gas Pipeline Co SW Trunk Vermont Gas Systems In Canada Trunk 100 NA NA NA NA NA Supplemental Pipeline Servie East Tennessee Natural Gas Co SW Trunk/Grid Usage rates are based upon apaity and transportation volumes for the whole system and do not represent regional servie only. 2 "Trunk systems are long-distane trunklines that generally tie supply areas to market areas. Grid systems are usually a network of many interonnetions and delivery points that operate in and serve major market areas. Some systems are a ombination of the two. 3 Represents the perent of total pipeline system volume delivered within the region on the system peak-day ourring in the heating year. 4 Represents total system apaity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 5 Represents total system apaity divided by the single peak-day volumes delivered in the heating year as reported in FERC Form 2. 6 Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based on FERC Form 11 gas delivery data for 1995) divided by 153 days. April and Otober are onsidered to be months that shoulder the heating season of November-Marh. NA = Not available. Soures: Capaity: Federal Energy Regulatory Commission, FERC 567 Capaity Report, System Flow Diagram and Annual Capaity Report (18 CFR );, EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity, as of Deember Delivery and Transport Volumes: Federal Energy Regulatory Commission, FERC Form 11, Natural Gas Pipeline Company Monthly Statement and FERC Form 2, Annual Report of Major Natural Gas Companies. 64

71 is an intrastate affiliated with ANR Pipeline Company, the addition, eah ompany has aess to numerous underground Iroquois Pipeline (0.9 Bf per day), and Tennessee Gas storage failities, allowing their shipper/ustomers to develop Pipeline Company s expansion of its Niagara import failities inventories of seasonal gas supplies for winter use. (by 0.5 Bf per day). Both ompanies are also the major suppliers of some of the In addition, several interstate pipelines serving the region largest LDCs in the region, many of whih are affiliates. From were signifiantly expanded. The largest expansion was on 1990 through 1996, Columbia added between 150 to the Texas Eastern Pipeline system (0.5 Bf per day) serving 200 MMf per day of apaity and CNG added about Pennsylvania, New York, and New Jersey, as well as southern 100 MMf to their systems. The primary expansion New England through servie to its affiliate, Algonquin Gas motivation in these two ases was to attrat additional Transmission Company (whih itself added about 122 million ustomers and improve overall servie in the region. ubi feet (MMf) per day of apaity). Transontinental Gas Pipeline Company, a major supplier to the region, Utilization rates tend to be muh lower on the more disperse, added approximately 165 MMf per day in the grid-type pipeline systems, suh as CNG and Columbia Gas Pennsylvania/New York area to improve its loal apabilities. Transmission. Grid systems funtion as distribution Its larger ontribution to regional servie, however, was a ompanies to the LDCs as well as transmission ompanies. major expansion in the Virginia/North Carolina area where The apaity to supply gas in one portion of the grid depends more than 420 MMf per day was added (1993). The latter upon how muh is being supplied out of the system by other projet oinided with improvements along muh of the portions of the grid. Both CNG and Columbia Gas Transo system extending from Louisiana to Virginia. Transmission have multiple lines rossing the State borders within the region, allowing gas to flow in both diretions at About three-quarters of the apaity into the region is the same time. The only high average-day utilization rate on supplied somewhat equally by three trunkline systems: Columbia Gas Transmission's system is at the Kentuky Transontinental Gas Pipe Line Corporation, Texas Eastern border, where it reeives Gulf-of-Mexio gas from its major Transmission Corporation, and Tennessee Gas Pipeline trunkline transporter, Columbia Gulf Transmission Company. Company. In 1996, the utilization rates on these pipeline CNG Transmission's lines serving the region, however, are systems as they entered the region averaged 80 perent. part of the grid and operated at an average utilization rate of Tennessee Gas Pipeline had the highest utilization about 31 perent in (90 perent) and the highest atual volume (2.8 Bf per day) into the region (Appendix A, Table A3). The flow of gas out of the region is almost exlusively to the Deliverability Within the Region Almost all of the interstate pipelines entering or operating within the Northeast Region terminate there; all have major delivery ommitments in the region (Figure 16). The largest systems target the New York City area as their primary market. The States of Pennsylvania and New York are the key transit points for gas deliveries within the region. These States, along with West Virginia, have the largest underground storage apaity in the region (Appendix C, Table C1), as well as some of the largest entering and exiting apaities and annual flow rates (Appendix A, Table A3). More pipeline apaity exits these States than enters, refleting their major storage apability as a seasonal supply soure for the States north and east. The largest major regional pipeline ompanies, CNG Transmission and Columbia Gas Transmission, have an extensive infrastruture and network of loal delivery points and pipeline interonnetions. They also have a number of reeipt points, where they bring in loal prodution soures to augment supplies from the Southwest and Canada. In Midwest (although some lines have bidiretional servie) over the many lines that were built around the turn of the entury to move loal prodution. West Virginia, western Pennsylvania, and southwestern New York were one the region s and the Nation s largest produing areas and, onsequently, have many loal gathering, distribution, and storage interonnetions. These areas also have many interonnetions with operations in Ohio, whih is the reason for the 2.0 Bf per day of apaity exiting the region to the Midwest. In addition to the interstate pipeline ompanies that bring gas into the region from the Midwest and Southeast, several smaller interstate pipeline ompanies operate totally within the region (Figure 16). Foremost among these is Algonquin Gas Transmission Company, whih has the apaity to move 1.2 Bf per day from New Jersey into New York (Appendix A, Table A3). During the heating season, peak-day deliveries for its entire system totaled about 1.5 million ubi feet. Algonquin, with 1,056 miles of trunk transmission lines, distributes the gas reeived in New Jersey to New York, Connetiut, Rhode Island, and Massahusetts. 65

72 The remaining small interstate pipeline ompanies averaged 79 only 32 MMf per day of interstate transmission in Storage Deliverability Many of the depleted gas fields in New York, Pennsylvania, and West Virginia are now used for storage, whih is essential for balaning gas supplies for the region (Table 10). Interstate apaity into the region, 12.4 Bf per day, ombined with loal prodution (approximately 1 Bf per day on average in 1996) is the equivalent of only about two-thirds of the peakday requirements within the region. The differene between this available system apaity and shipper and onsumer demand is designed to be met by withdrawals from storage. During the heating season, average daily withdrawals in the region were about 4.9 Bf; during January 1997, the month with the highest average, storage deliverability averaged 7.7 Bf per day. 80 The growth in the Northeast market has also spurred numerous storage projets. Plans are underway to inrease storage deliverability in the region 17 perent by 2000; this would inlude new installations or expansions at 37 or more 81 of the 121 storage sites in the region. Almost all of the expansions would be at 35 sites owned and operated by Columbia Gas Transmission Company. LNG storage is also being inreased in the New England market to provide peaking support to those LDCs that will be reeiving supplies along new pipeline routes whih are not onvenient to underground storage failities. Compared with other market areas, the Northeast makes the most extensive use of LNG (Table 10). The peak-day deliverability from LNG in the region, 3.8 Bf per day, is 32 perent as large as the total daily deliverability from underground storage failities. This bakup apability has been inluded in the overall design of the regional network and is neessary to meet the rapid inreases in demand that an our beause of sudden temperature hanges. End-Use Consumption Although the Northeast has the highest energy onsumption of the regions, natural gas is a relatively low proportion of total energy onsumed: 21 perent versus a national average of about 24 perent (Table 11). Yet, sine 1990, the average 79 Federal Energy Regulatory Commission, FERC Form 2 and 2A, Annual Report of Natural Gas Companies, , Form EIA-191, Underground Gas Storage Report. 81, U.S. Underground Storage of Natural Gas in 1997: Existing and Proposed, Natural Gas Monthly, annual growth in natural gas demand in the region grew at a faster rate than the growth in overall energy use, 4.9 perent versus 1.2 perent (Table 11). This average annual growth in natural gas demand, as well as the spread between natural gas and overall energy use, was among the highest of the six regions examined. Most of this growth an be attributed to the industrial setor, where natural gas onsumption grew at an annual rate of 8.3 perent (Table 12) while per-ustomer usage grew at a 9.7 perent rate (Table 13). Refleted in these rates were large inreases in industrial use in New York and New Jersey (Appendix C, Table C3). The inrease in industrial gas use ame despite a 1.5 perent per annum drop in the industrial ustomer base during the period. Eletri utilities in the region had a derease in natural gas use, whih delined at an average annual rate of 4.7 perent during the period. This ourred in spite of a growth in gaspowered generating apaity in the region. While the number of gas-fired eletri generating units in the Northeast (exluding industrial ogeneration apaity) inreased by only 0.4 perent per annum, generating apaity grew at a 4.4 perent annual rate (Table 13). Currently, about 14 perent of the generating apaity in the region is gas-fired and, oinidently, gas-fired generating apaity in the region also represents 14 perent of total U.S. gas-fired generating apaity. 82 Although industrial use of natural gas ontinues to grow, residential ustomers in the region still remain the primary users of natural gas. They aounted for 35 perent of the gas onsumed in the region in 1996, in ontrast to the national average of 24 perent. Although the population of the region is estimated to have inreased by only 0.7 perent per annum (Table 11) between 1990 and 1996, total gas onsumption in the region inreased at a 4.9 perent rate. Spae-heating gas demand in the region is driven by the growing, highly populated urban orridor that strethes from Boston, Massahusetts, to Rihmond, Virginia. Reent and Proposed Expansions In 1997, 12 expansion projets were ompleted in the Northeast, inreasing overall deliverability within the region by more than 772 million ubi feet per day (Appendix B, Table B1). Only one projet brought additional gas into the region; the rest were implemented to improve loal deliverability to expanding markets within the region. Numerous other projets have been proposed for the Northeast market that ould inrease apaity by more than 82 Derived from:, Form EIA-860, DOE/EIA-0130(97)/9) (Washington, DC, September 1997) Annual Eletri Generator Report ( ). 66

73 7 Bf per day. Planned expansions into the region would total Capaity into the Southeast Region grew by slightly more 4.0 Bf per day, or 32 perent above the 1996 level. than 7 perent between 1990 and 1996 (Table 9). Most Inreasing demand for natural gas servie in the region and apaity additions ourred within the region. The major the readiness of Canadian produers to meet the need underlie projets ompleted were the Florida Gas Transmission the bulk of the expansions. Long dependent on fuel oil, the expansion, the Mobile Bay Pipeline, and the Transontinental Northeast has seen a steady inrease in the availability of Gas Pipeline southern expansion. Noteworthy were the natural gas in reent years. additional pipeline expansions serving the northern North Carolina market. Several pipelines from the Northeast Region While a large portion of the antiipated growth in natural gas (Columbia Gas Transmission and Transontinental Gas demand is expeted to ome from inreased usage by the Pipeline Company) extended their systems into the Southeast industrial setor, the major growth market is expeted to be market in the eletri utility setor. Several nulear generating stations in the region are slated for retirement during the next several More natural gas pipeline apaity (exluding offshore-toyears and will be replaed by nonnulear plants. The natural onshore) enters and exits Mississippi than any other State in gas pipeline industry believes that many of these replaement the Nation (Appendix A, Table A4). It is the hub State for failities, as well as a number of new onventional apaity into the region, with 21.3 Bf per day oming into power plants, will be built during the next deade and will use the State and 20.5 Bf per day leaving the State. While high-effiieny natural-gas-turbine tehnology more widely. several routes flow southward toward Florida, most are At the same time eletriity demand in the region is expeted direted to the Northeast and Midwest regions (Appendix A, to grow as the effets of eletri industry deregulation widen Figure A4). ompetition in the market. Fifteen interstate pipeline ompanies operate within the region, with all but four transporting gas from the Southwest. Southeast Regional Market By apaity level, the largest transporters are Tennessee Gas Pipeline Company, Transontinental Gas Pipe Line Corporation, Texas Eastern Transmission Corporation, and Texas Gas Transmission Corporation. These same four are also the largest exporters. The Southeast Region is the least developed market for natural gas in terms of per-apita onsumption. In fat, natural gas aounts for only a small perentage of the total energy onsumed in the region (Table 11). However, beause of its proximity to major produing areas in the Southwest, numerous interstate natural gas pipeline ompanies operate throughout the region (Appendix A, Figure A4), transporting signifiant volumes via the region to the Northeast and Midwest markets. Although the region has only limited storage apaity, numerous high-deliverability storage sites exist in the southern part of the region, many of whih have been developed sine Four suh sites were added in Mississippi, whih has several major interstate pipelines traversing the State en route to Northeast markets. The availability of these sites has made the State a prime market for the type of storage servies needed by shippers with high upstream demand swings and load balaning requirements. Entering/Exiting Capaity During peak periods, the interstate pipeline system has the apaity to move up to 21.4 Bf into the Southeast Region, prinipally from the Southwest (Figure 17). This is the seond-largest apaity level into any region. More than 70 perent of this apaity is redireted out of the region, with 9.8 Bf per day into the Midwest and 5.1 Bf per day into the Northeast Region. On its system peak day in 1995, Tennessee Gas Pipeline transported only about 30 perent of its volumes to delivery and interonnetion points in the Southeast Region. 83 Likewise, Transontinental Gas Pipe Line, whih traverses the region via the Carolinas, delivered only 33 perent of its peak-day volumes in the Southeast. In 1996, average utilization rates on Transontinental's lines en route to the weather-sensitive Northeast were 83 perent in Mississippi and 79 perent out of Virginia (Appendix A, Table A4). The average daily flow of natural gas into Mississippi in 1996 averaged 16.1 Bf: 10.9 Bf from Louisiana, at 79 perent of apaity, and 5.1 Bf from Arkansas at 73 perent of apaity. The ombined utilization on lines entering Mississippi in 1996 was 77 perent. Major shippers on the major interstate pipeline systems serving the region have peak-day demands of approximately 9.4 Bf per day. Within the region, demand requirements are the largest in Tennessee, primarily beause of the interonnetions and servie provided among several interstate pipeline ompanies rather than servie to LDCs. Based on oinidental peak-day deliveries reported on the annual FERC 83 System Flow Format 567 report. 67

74 Figure 17. Interstate Natural Gas Capaity Summary for the Southeast Region, 1996 (Volumes in Million Cubi Feet per Day) Midwest 5,149 OH Region 9,821 4,462 IN 2,361 WV Kentuky IL 3,559 VA 25 1, ,587 MO 12, Tennessee , ,342 3, South Carolina Southwest 7,026 5,129 Region AR ,269 3,471 LA Alabama 20,846 13,821 Georgia 1, Mississippi Northeast Region 520 North Carolina Estimated Total Throughput Capaity Entering: 21,366 (exludes Gulf of Mexio) Leaving: 15, Florida Prinipal Interstate Natural Gas Pipeline Companies Operating in the Southeast Region Regional Servie Level Systemwide Utilization Rates 1 % Primary/ Perent of Number Number Regional Seondary System of of Prinipal Market Region / Supply System Peak-day Delivery Interon- 12-Month Peak Summer Pipeline Name Soure(s) 2 Configuration 3 Deliveries Points nets 4 Average 5 Day 6 Offpeak Regional Pipelines Columbia Gulf Transmission Co SW Trunk East Tennessee Natural Gas Co SW Grid/Trunk Florida Gas Transmission Co SW Trunk Midoast Pipeline Co SW Trunk/Grid 100 NA NA NA NA NA South Georgia Natural Gas Co SW Grid NA NA NA Southern Natural Gas Co SW Grid/Trunk Texas Gas Transmission Co SW Trunk Supplemental Pipeline Servie ANR Pipeline Co SW Trunk/Grid Columbia Gas Transmission Corp SW, NE Grid Koh Gateway Pipeline Co SW, SE Grid/Trunk Midwestern Gas Transmission Co SW Trunk Tennessee Gas Pipeline Co SW, Canada Trunk Texas Eastern Transmission Corp SW Trunk Transontinental Gas Pipeline Co SW Trunk Trunkline Gas Co SW Trunk Usage rates are based upon apaity and transportation volumes for the whole system and do not represent regional servie only. 2 "Trunk systems are long-distane trunklines that generally tie supply areas to market areas. Grid systems are usually a network of many interonnetions and delivery points that operate in and serve major market areas. Some systems are a ombination of the two. 3 Represents the perent of total pipeline system volume delivered within the region on the system peak-day ourring in the heating year. 4 Represents total system apaity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 5 Represents total system apaity divided by the single peak-day volumes delivered in the heating year as reported in FERC Form 2. 6 Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based on FERC Form 11 gas delivery data for 1995) divided by 153 days. April and Otober are onsidered to be months that shoulder the heating season of November- Marh. NA = Not available. Soures: Capaity: Federal Energy Regulatory Commission, FERC 567 Capaity Report, System Flow Diagram and Annual Capaity Report (18 CFR );, EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity, as of Deember Delivery and Transport Volumes: Federal Energy Regulatory Commission, FERC Form 11, Natural Gas Pipeline Company Monthly Statement and FERC Form 2, Annual Report of Major Natural Gas Companies. 68

75 Deliverability Within the Region Loal gas servie within the region, for the most part, is haraterized by the presene of a large number of distributors per State, although in most States only one or two large ompanies predominate. For example, while Georgia has 90 LDCs, the largest one, Atlanta Gas Light Company, represents nearly three-quarters of the total ommitments on interstate pipeline apaity in the State. Southern Natural Gas Company provides most of the gas sold by Atlanta Gas Light. The States of North and South Carolina are exeptions to this regional pattern of having many different pipeline ustomers. Eah of these States has fewer than 25 LDCs, most of whih are quite small representing less than 15 perent of peak-day deliveries on the interstate systems serving the respetive States. The Carolinas were not served by any interstate natural gas pipeline until after World War II. Most of the interstate pipeline servie (more than two-thirds) in North Carolina and South Carolina is from Transontinental Gas Pipe Line Corporation. Southern Natural Gas Company also supplies ustomers in South Carolina. LDCs that serve loal markets in Louisville, Kentuky, and Evansville, Indiana. Nevertheless, while most of the remaining storage in Kentuky (representing about 67 perent of the daily peak-day withdrawal apability in the State) is owned by interstate operators, the bulk of its working gas apaity and deliverability servie is reserved by LDCs in northern Kentuky, southern Ohio, Indiana, and Illinois. Four-fifths of the storage apaity in Kentuky is owned by one interstate pipeline ompany, Texas Gas Transmission Corporation. The ompany's storage failities have a total estimated peak-day delivery rate of about 1.2 Bf per day, about 70 perent of the total within the State. This level is equivalent to about 80 perent of the total daily apaity of Texas Gas Transmission's lines moving north into Indiana. These storage failities are also in lose proximity to the ANR Pipeline Company system, whih traverses the State to Indiana and Mihigan. Combined, Texas Gas Transmission and ANR Pipeline have the apaity to move 2.9 Bf per day north to Indiana (Appendix A, Table A2); Texas Gas Transmission's peak-day storage delivery level is the equivalent of about 42 perent of that figure. End-Use Consumption The largest peak-day delivery volume in the region is 1.7 Bf per day by Columbia Gulf Transmission Corporation to its affiliate, Columbia Gas Transmission Company, in Kentuky. Eonomi growth in reent years has led to inreased natural Columbia Gas of Kentuky, an LDC, in turn reeives about gas use in the Southeast marketplae. Natural gas inreased its 0.2 Bf per day of that total from Columbia Gas Transmission share of the energy market, outpaing the growth in total Corporation. Louisville Gas & Eletri Company and Western energy usage, 2.9 perent per year versus 2.2 perent Kentuky Gas Company are the largest LDCs in Kentuky. (Table 11). Refleting this growth, in 1995, natural gas use in Their shipments with Texas Gas Transmission Corporation the region stood at 15 perent of total energy used, 2 perent aount for about three-quarters of the pipeline ompany's greater than in Still, the Southeast remains the smallest total deliverability within the State. onsumer of natural gas of all the regions. Storage Deliverability Although the Southeast has the least underground storage apaity of the regions, it has the largest perentage of its daily deliverability (47 perent) from high-deliverability storage sites (Table 10), whih are mainly loated in Mississippi and Alabama. These failities are used primarily by shippers on the interstate pipeline system to balane their loads on lines rossing into Alabama and points north and east and to aommodate the periodi swings in demand that are harateristi of some industrial and eletri utility users. In Mississippi, interstate shippers and loal onsumers have aess to a delivery (withdrawal) apability equivalent to 2.2 Bf per day from salt dome storage sites (Appendix C, Table C1). In the northwestern part of the region, in Kentuky, all of the storage sites are onventional depleted reservoirs, whih are used primarily for seasonal supply and bakup. About 32 perent of this underground storage apaity is owned by Temperate weather, abundant regional oal reserves, and the long history of eletriity use fostered by the Tennessee Valley Authority (TVA) have ombined to keep residential use of natural gas relatively low. The residential share of natural gas in the region is less than half that of the industrial share, although the residential share has inreased 2 perentage points sine 1990 beause of an inreased number of ustomers during the period (Table 12). The States with the largest residential natural gas markets in the region are Georgia (33 perent) and Kentuky (30 perent) (Appendix C, Table C3). While the industrial setor inreased its onsumption of natural gas at an annual rate of 3.2 perent between 1990 and 1996, its share within the natural gas market fell several perentage points (Appendix C, Table C3). Nevertheless, this setor urrently represents 44 perent of the natural gas usage within the region, the highest share for the industrial setor in any region exept the Southwest (Table 12). Average use by industrial ustomers inreased at an average annual rate of 69

76 almost 1.4 perent in the early 1990s (Table 13) after delining throughout the latter part of the 1980s. The eletri utility setor share also grew during the early 1990s as more gas-fired units were installed at eletri generating plants in the region. From 1990 through 1996, gasfired generating apaity grew at an annual rate of 4.2 perent ompared with a 1.2 perent growth rate in total generating apaity installed. In 1996, gas-fired generating apaity aounted for 10 perent of the total, ompared with only 4 perent in Currently, this setor represents 16 perent of the natural gas market in the region, up 1 perentage point sine Its share an be expeted to inrease during the next several years, even if the annual growth rate slows from the 8.3 perent pae during the period from 1990 through Reent and Proposed Expansions The ontinuing deline in deliverability from the western Gulf of Mexio and the inreasing development of deep water prodution in the eastern part of the Gulf (see Chapter 2) is expeted to result in greater apaity utilization on the major trunklines traversing the Southeast Region. New apaity ould be needed in the near future, but, as of Marh 1998, no major expansions have been submitted to FERC for approval. Only Columbia Gulf Transmission Company (0.2 Bf per day) and Tennessee Gas Pipeline Company (0.2 Bf per day) have announed proposals that would address this issue (Appendix B). Most of the expansion proposals into and within the region are targeted toward improving deliverability to regional ustomers and expanding into new market areas. In 1997, five projets were ompleted, aounting for only 0.4 Bf per day of new apaity (Table ES1). This is equivalent to only about 0.5 perent of existing interstate pipeline apaity in the region (Appendix B). More than 3.2 Bf of new apaity has been proposed within the region for ompletion between 1998 and 2000 (Appendix B, Table B2). About 54 perent of this apaity is to bring in supplies from the Gulf of Mexio. While almost all of the onshore projets are regional, and for the most part support the area s expanding eletri utility and industrial setors, the offshore projets are designed to support the interstate pipeline network as well. Demand for natural gas is still growing within the region. More natural gas is being used by all ustomer groups, inluding eletri utilities (Table 12). In fat, natural gas demand in the region grew at an annual average rate of 3 perent between 1990 and 1995, with eah ustomer ategory showing an inrease. With pipeline utilization rates within the region also showing an inrease over the past several years (about 8 perentage points), inreased expansion planning in the region an be expeted. Southwest Regional Market Even though large volumes of natural gas leave the Southwest Region for other regional markets, signifiant volumes still remain in the region to fulfill a high level of industrial demand enouraged over the years by the proximity to prodution areas. In 1996, the Southwest Region onsumed more natural gas than any other region, one-half more than the next largest onsuming region, the Midwest. About onethird of the Nation's gas is onsumed in the Southwest. The region also has numerous underground storage reservoirs, most of whih are used to store exess natural gas prodution during months of low onsumption (Table 10). In reent years, however, more storage in the region is being devoted to supporting the needs of ustomers using natural gas market enters in the area. Total working gas storage apaity (983 Bf) is the seond highest of the regions. The region has temperate winters and long, hot summers. Louisiana and Texas are the seond- and third-warmest States in the lower 48 States, whih aounts for large eletriity loads for air-onditioning servies. Entering/Exiting Capaity Beause the Southwest Region has many of the largest gasproduing areas in North Ameria, a huge amount of natural gas pipeline apaity in the region represents export apability. More than 35.7 Bf per day of apaity exits the region (Figure 18) on at least 20 interstate pipelines (Appendix A, Figure A5), direted toward markets in all other regions of the ountry, as well as Mexio. This represents an 8-perent inrease sine 1990 (Table 7, Chapter 3), most of whih was evenly distributed on pipelines extending to the Western and Southeast regions (Appendix A, Table A5). From 1990 to 1996, average daily pipeline utilization rates inreased along eah of the exiting orridors exept into the Western Region (and Mexio). The installation of exess interstate pipeline apaity, oupled with an eonomi downturn in that region, brought on a sizable drop in usage rates along the Western orridor. Only about 2.9 Bf per day of apaity enters the Southwest Region. Muh of this apaity is on pipeline systems whose flows are direted toward interonnetions with other interstate systems for transshipment to markets outside the Southwest Region. The remainder represents flows to loal regional markets that are lose to the borders of the region, 70

77 Figure 18. Interstate Natural Gas Capaity Summary for the Southwest Region, 1996 (Volumes in Million Cubi Feet per Day) Western Region 5,351 AZ UT CO 5, , ,266 New Mexio 2,114 Central Region 8,609 KS MO 47 5,272 TN 2,814 Oklahoma 25 2,795 Arkansas 1, MS 706 4,250 5,926 2,160 20,846 7, Louisiana Texas 5, , Southeast Region 350 Mexio ,636 Estimated Total Throughput Capaity 350 Entering: 2,869 (exludes Gulf of Mexio) Leaving: 35,650 Prinipal Interstate Natural Gas Pipeline Companies Operating in the Southwest Region Regional Servie Level Systemwide Utilization Rates 1 % Primary/ Perent of Number Number Regional Seondary System of of Prinipal Market Region / Supply System Peak-day Delivery Interon- 12-Month Peak Summer Pipeline Name Soure(s) 2 Configuration 3 Deliveries Points nets 4 Average 5 Day 6 Offpeak Regional Pipelines Koh Gateway Pipeline Co SW Trunk/Grid Noram Gas Transmission Co SW Trunk/Grid Mid-Louisiana Gas Co SW Trunk NA NA NA Ozark Gas Transmission Co SW Trunk 100 NA NA NA NA NA Valero Interstate Transmission Co SW Trunk/Grid 100 NA NA NA NA NA Supplemental Pipeline Servie ANR Pipeline Co SW Trunk/Grid Colorado Interstate Gas Co SW, CE Trunk/Grid Columbia Gulf Transmission Co SW Trunk El Paso Natural Gas Co SW Trunk Florida Gas Transmission Co SW Trunk Mississippi River Transmission Co SW Trunk Natural Gas Pipeline of Ameria SW, CE Trunk Northern Natural Gas Co SW Trunk/Grid Panhandle Eastern Transmission Co SW Trunk Southern Natural Gas Co SW Grid/Trunk Tennessee Gas Pipeline Co SW, Canada Trunk Texas Eastern Transmission Corp SW Trunk Texas Gas Transmission Corp SW Trunk Transontinental Gas Pipeline Co SW Trunk Trunkline Gas Co SW, CE Trunk Transwestern Gas Pipeline Co SW, CE Trunk Williams Natural Gas Co SW, CE Grid/Trunk

78 1 Usage rates are based upon apaity and transportation volumes for the whole system and do not represent regional servie only. 2 "Trunk systems are long-distane trunklines that generally tie supply areas to market areas. Grid systems are usually a network of many interonnetions and delivery points that operate in and serve major market areas. Some systems are a ombination of the two. 3 Represents the perent of total pipeline system volume delivered within the region on the system peak-day ourring in the heating year. 4 Represents total system apaity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 5 Represents total system apaity divided by the single peak-day volumes delivered in the heating year as reported in FERC Form 2. 6 Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based on FERC Form 11 gas delivery data for 1995) divided by 153 days. April and Otober are onsidered to be months that shoulder the heating season of November- Marh. NA = Not available. Soures: Capaity: Federal Energy Regulatory Commission, FERC 567 Capaity Report, System Flow Diagram and Annual Capaity Report (18 CFR );, EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity, as of Deember Delivery and Transport Volumes: Federal Energy Regulatory Commission, FERC Form 11, Natural Gas Pipeline Company Monthly Statement and FERC Form 2, Annual Report of Major Natural Gas Companies. for example, Assoiated Natural Gas Company s 30 MMf gathering and intermediate storage operations within the per day from Missouri into Arkansas. region performed in onjuntion with prodution features that affet trunkline operations to a lesser degree. Also, About 45 perent (1.3 Bf per day) of the total entering trunkline usage rates often are more a refletion of the apaity represents pipeline apaity from Colorado (Central downstream demands of other regional markets rather than of Region) to New Mexio on three pipelines (Appendix A, demands within the Southwest. Table A5). Part of this apaity (about 60 perent) is redireted toward traditional Western Region markets, The regional interstate pipeline ompanies, that is, those with although in reent years a greater portion of this apaity is the majority of their deliveries within the region, together being direted to interstate interonnetions and market aount for about one-quarter of the regional deliveries. Most enters that serve the Midwest marketplae. The average daily of the regional onsumption is supplied by loal intrastate utilization rates on these three pipelines ranged from 55 to pipeline ompanies for whih data are unavailable. As the 88 perent in 1996, the lowest being on the Transwestern largest onsuming region in the United States, the Southwest Pipeline system, whih was affeted by unusual maintenane has many large intrastate pipeline ompanies and LDCs needs and onstrution during off-peak periods. supplying natural gas to onsumers. For example, Lone Star Gas Company is the eighth largest LDC in the United States Deliverability Within the Region (in terms of total deliveries), with more than 1.2 million ustomers in Texas. The only States in whih LDCs are among the largest ustomers of the interstate pipeline ompanies are Louisiana, where Koh Gateway Pipeline Company supplies New Orleans Publi Servie In., and New Mexio, where El Paso Natural Gas Company supplies three LDCs. Several of the 22 or more interstate pipeline ompanies operating within the Southwest Region primarily serve ustomers in the region (Figure 18). Three of the larger ones, Noram Gas Transmission Company, Ozark Gas Transmission Company, and Valero Interstate Pipeline Company, have ommitments within the region of lose to 100 perent of their total transportation servie levels. In addition, several of the major trunklines exiting the region also maintain sizeable deliverability levels within the region itself. For instane, in Storage Deliverability Underground natural gas storage plays a vital role in the 1995, El Paso Natural Gas, Koh Gateway Pipeline, and effiient export and transmission of natural gas from the Transwestern Pipeline ompanies delivered 54, 63, and Southwest to other regions, as well as in supplementing 53 perent, respetively, of total throughput to points within regional needs. These underground storage failities represent 84 the region on their system peak day. Several of the other over 982 Bf of working gas apaity (Table 10) and an major exporting pipeline system delivered 25 to 30 perent of estimated daily deliverability level of over 20.5 million ubi their peak-day volumes within the region. feet. A large portion of this storage is near prodution fields and is used to balane prodution flows and flutuating marowned storage, and most of the independently owned, is open In 1996, the average daily utilization rates on the interstate ket demand. pipelines within the region ranged from 42 to 98 perent. In general, the average rate within the region was higher in About 38 perent of the region s daily deliverability from 1996 than in 1990, 57 versus 49 perent. This rate is lower storage is owned by interstate pipeline ompanies, 29 perent than the 66-perent average utilization for lines exiting the by independent operators, and 33 perent by LDCs or region (Appendix A, Table A5), but reflets some of the intrastate pipeline ompanies. All of the interstate pipeline- aess, that is, working gas storage apaity an be available to shipper/ustomers on a first-ome, first-served basis at nondisriminatory rates. This means that only a limited amount of the pipeline storage is for system or pipeline use, EIAGIS-NG Geographi 84 Information System, Natural Gas Pipeline Deliverability Database, as of Deember

79 (for load-balaning operations). Most shippers are now attributed to an annual growth rate of only 1.9 perent in responsible for making their own arrangements with storage residential onsumption and 3.2 perent in the industrial operators to ensure that they omply with the reeipt/delivery setor (Table 12). balaning requirements of the system on whih they are shipping. Although eletri utility use of natural gas showed a slight annual derease (0.1 perent) during the period (Table 12), As a result, a growing amount of regional storage is also gas-fired generating apability inreased at a 1.4 perent rate. linked to the many natural gas market enters in the region Gas-fired generating apaity grew to 57 perent of total 85 that have beome operational during the past 5 years. These eletri generating apaity in the region by 1996, the highest enters, often themselves owners of independent storage, rate among regions. Louisiana had the highest perentage, assist shippers in making short-term arrangements to store perent, with Texas seond at 61 perent. Total exess load or to borrow gas when reeipt volumes do not eletriity generating apaity in the region inreased by only math delivery requirements or vie-versa, a situation that an 2 perent from 1990 through 1996, at about the same level as result in imbalane penalties being levied by the transporting installed gas-fired units (Table 13). On the other hand, pipeline. nonutility generating apability, although aounting for only about 1 perent of eletri power generated in the region in The overall peak-day withdrawal apability from storage into 1996, grew by 14 perent during the same period. the interstate system is approximately 13.7 Bf per day (Table 10), the equivalent of about 39 perent of the total In 1990, natural gas provided 40 perent of the total energy apaity exiting the region. In Louisiana, almost all of the un- 88 input to eletri utilities in the region. By 1996, this derground storage servie is available to the interstate system, proportion had fallen to 36 perent. In addition, the total whereas in Oklahoma, 56 perent is operated as part of the volume of gas onsumed within the region by eletri utilities 86 interstate system (Appendix C, Table C1). Industrial and 89 delined by 7 perent during the same period. In spite of this eletri utility ustomers in the region, with variable load regional deline, natural gas use by eletri utilities in Texas demands and high swing requirements, are major users of inreased slightly and in 1996 still aounted for 40 perent high-deliverability, salt avern storage, most of whih is of all gas purhases by utilities in the Nation. operated by interstate pipeline ompanies or independents. Despite a slight loss in energy share, regional onsumption of Only about a third of the region's storage apaity is owned natural gas is the highest in the Nation. Louisiana, Oklahoma, by LDCs and used exlusively for loal servie (Table 10), New Mexio, and then Texas, respetively, use natural gas as but regional distributors also have aess to and use interstate an energy soure to a greater degree than any other States in and independent storage failities. Most of the LDC-owned the Nation (Appendix C, Table C2). This high level is due to storage is near major industrial and population enters and has the availability of gas in the region, where the overall ratio of little impat upon the interstate pipeline network in the area. natural gas prodution to onsumption is 2.25 (Table 11), and In Texas and Oklahoma, approximately 40 perent of the use of natural gas by industries and eletri utilities in the underground storage apaity is at failities operated by LDCs region is still the highest ompared with use in the rest of the or intrastate pipeline ompanies, whereas in Arkansas all of Nation (Table 12). the storage apaity is ontrolled by loal operators (Appendix C, Table C1). The industrial setor dominates the regional market, End-Use Consumption The Southwest is the only regional marketplae where natural gas use grew at a slower rate than total energy demand (Table 11). Sine 1990, natural gas onsumption in the region grew at an annual rate of 0.2 perent, while total energy grew at a 1.3 perent rate. In fat, the use of natural gas as a perentage of total energy onsumed dropped from 40 perent in 1990 to 39 perent in Part of this drop an be onsuming 53 perent of the natural gas delivered within the Southwest Region. The industrial share of natural gas onsumption is highest in Louisiana (63 perent) beause of its large petrohemial industry. From 1990 to 1996, industrial ustomers in all States in the region inreased average natural gas use at an annual rate of 11 perent, with New Mexio (where industrial setor represents the smallest 87 Derived from:, Form EIA-860, Annual Eletri Generator Report ( ). 88 During the 1980s, the proportion of natural gas onsumed by eletri utilities in the region dropped from 66 perent in 1980 to 41 perent in See,, Natural Gas 1996: Issues and primarily beause of high gas pries that developed in the early part of the Trends, DOE/EIA-0560(96) (Washington, DC, Deember 1996),Table 8, deade. 89 Chapter 3., Natural Gas Annual 1996, 86 Inludes supply to the interstate system. DOE/EIA-0131 (Washington, DC, September 1997) and previous editions. 73

80 market share) and Texas showing the largest inreases California have mandated redutions in onsumption of (Appendix C, Table C4). While natural gas lost in terms of residual fuel oil as a boiler fuel, resulting in inreased use of overall industrial gas users, its share of the regional natural natural gas in this area. Even before passage of the Clean Air gas market still grew by 6 perentage points between 1990 At Amendments of 1990, the South Coast Air Quality and 1996 (Table 12). Management Distrit issued rules that prohibit prie-indued burning of fuel in dual-fired utility boilers. The Southern The residential and ommerial use of natural gas remains California Edison Company and the Los Angeles Department relatively low in the region, representing only about 11 of Water and Power also adopted plans that would eliminate perent of natural gas onsumption in the region, virtually the use of fuel oil at all their power plants in order to redue unhanged from the 1990 level. The Southwest is only fourth emissions. of the six regions in the proportion of the total population that uses natural gas, and also fourth in terms of average gas use This projeted preferene for gas beause of environmental 90 per residential ustomer. Sine 1990, the number of onerns was a primary fore behind the 42-perent inrease residential and ommerial gas ustomers inreased in pipeline apaity into the Western Region between 1990 somewhat, 1.2 and 2.2 perent per year, respetively, but not and However, the expeted growth in the natural gas enough to affet their respetive markets (Table 13). market did not materialize as an eonomi slowdown resulted in underutilization of this new apaity. Reent and Proposed Expansions The prinipal arena for pipeline apaity expansions in the Southwest Region during the next several years will be in the intrastate market, mostly to expand aess to new prodution areas and improve deliverability to loal markets and links with the interstate system. In partiular, produers in southern Texas and the Cotton Valley Trend area of eastern Texas will be seeking greater aess to the interstate transmission network. In the interstate market, the primary effort will be to forge greater aess to deep water developments in the Gulf of Mexio and to improve servie at the several market enters in the region. California dominates the regional natural gas market beause of its large population, the highest in the Nation, and beause of its relatively high gas use. California ustomers aount for about 59 perent of the energy onsumed in the region and 74 perent of the natural gas use (Appendix C, Table C2). One utility, Paifi Gas and Eletri, distributed almost 5 perent of the natural gas delivered to end-use ustomers in the United States in Another, Southern California Gas Company, is the largest gas distributor in the United States and perhaps in the world. Entering/Exiting Capaity In 1997, 10 expansion projets were ompleted within the Eight interstate pipeline ompanies provide servie to and region, adding more than 3.7 Bf to regional pipeline within the Western Region, the fewest number serving any apaity. Six of these projets were designed to bring region (Figure 19). Capaity entering the region is also the additional supplies onshore from the Gulf of Mexio: three lowest of all gas-importing regions, approximately 10.1 Bf major gathering systems (1.1 Bf per day) and three pipelines per day. Slightly more than half of this apaity is on pipeline (2.1 Bf per day) oming onshore to Louisiana (Appendix B). systems that arry gas from the Roky Mountains area and the The remaining projets were designed prinipally to expand Permian and San Juan Basins (Appendix A, Figure A5). interstate aess to prodution in West Texas and New These systems enter the region at the New Mexio-Arizona Mexio. Fourteen additional projets are sheduled for and Nevada-Utah State lines. The rest arrive on pipeline ompletion in 1998 and two in 1999, whih would add systems that aess Canadian supplies at the British 3.7 Bf to regional apaity. Currently, no projets have been Columbia-Idaho and Washington State border rossings. announed that would go beyond Capaity into the Western Region inreased overall by 42 perent, or 3.0 Bf per day, between 1990 and 1996 Western Regional Market (Table 9). The majority of this inrease ourred on routes transporting gas from Canada, where 48 perent more The Western Region has some of the strongest environmental apaity was implemented. PG&E Transmission-Northwest initiatives in the Nation, many of whih all speifially for (formerly Paifi Gas Transmission Company) and Northwest greater use of natural gas. For instane, regulatory agenies in Pipeline Company aounted for all of these apaity additions. In spite of a general eonomi downturn in the region during the early 1990s, partiularly in California, average apaity usage rates on these routes reovered in See,, Natural Gas Annual 1996, and 90 previous editions. 74

81 1996 (after falling between 1993 and 1995) to reah or exeed their 1990 average rates. Three new interstate natural gas pipeline systems were plaed in servie between 1991 and 1995 in the region and four existing systems underwent major expansions. While they were being built, however, the regional marketplae, espeially in California, saw an overall derease in eonomi ativity and a slowdown in the growth of natural gas demand. A asualty of the slowdown has been the repeated postponement of the Altamont Pipeline projet (737 MMf per day), whih was slated to serve the California market with 91 gas transported from western Canada. Currently, the projet is being marketed as a potential route for transporting Canadian supplies eastward via the expanding Trailblazer system (whih transports gas to Midwestern markets). The Altamont system, as originally proposed, would flow southward 91 from Alberta, Canada, through Montana and feed into the Kern River pipeline system at Opal, Wyoming. 75

82 Figure 19. Interstate Natural Gas Capaity Summary for the Western Region, 1996 (Volumes in Million Cubi Feet per Day) Canada 3,786 1,126 2,660 Washington 2, MT 2, Oregon 2,063 Idaho 254 WY California Nevada UT 298 Central Region 1,194 Estimated Total Throughput Capaity Entering: 10,674 (exludes offshore) Leaving: Mexio Arizona 5,118 NM 5,331 Southwest Region 5,351 Prinipal Interstate Natural Gas Pipeline Companies Operating in the Western Region Regional Servie Level Systemwide Utilization Rates 1 % Primary/ Perent of Number Number Regional Seondary System of of Prinipal Market Region / Supply System Peak-day Delivery Interon- 12-Month Peak Summer Pipeline Name Soure(s) 2 Configuration 3 Deliveries Points nets 4 Average 5 Day 6 Offpeak Regional Pipelines El Paso Natural Gas Co. SW None Kern River Transmission Co CE Trunk Mojave Pipeline Co SW Trunk Northwest Pipeline Co Canada Trunk/Grid Paifi Gas Transmission Co Canada Trunk TransColorado Pipeline Co CE Trunk 100 NA NA NA NA NA Transwestern Gas Pipeline Co SW Trunk Tusarora Gas Transmission Co Canada Trunk NA NA NA 1 Usage rates are based upon apaity and transportation volumes for the whole system and do not represent regional servie only. 2 "Trunk systems are long-distane trunklines that generally tie supply areas to market areas. Grid systems are usually a network of many interonnetions and delivery points that operate in and serve major market areas. Some systems are a ombination of the two. 3 Represents the perent of total pipeline system volume delivered within the region on the system peak-day ourring in the heating year. 4 Represents total system apaity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 5 Represents total system apaity divided by the single peak-day volumes delivered in the heating year as reported in FERC Form 2. 6 Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based on FERC Form 11 gas delivery data for 1995) divided by 153 days. April and Otober are onsidered to be months that shoulder the heating season of November- Marh. NA = Not available. Soures: Capaity: Federal Energy Regulatory Commission, FERC 567 Capaity Report, System Flow Diagram and Annual Capaity Report (18 CFR );, EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity, as of Deember Delivery and Transport Volumes: Federal Energy Regulatory Commission, FERC Form 11, Natural Gas Pipeline Company Monthly Statement and FERC Form 2, Annual Report of Major Natural Gas Companies. 76

83 The new pipeline systems onstruted during the period Arizona two, and California five. In addition, a ompany suh inlude: (1) the Kern River Pipeline (750 MMf per day) as Washington Water Power operates in more than one State, from Opal, Wyoming, to Kern County, California, urrently providing servie in Oregon, Washington, and California. operating at about 100 perent utilization during peak periods and 93 perent during baseload periods; (2) Mojave Pipeline Until the early 1990s no interstate pipeline ompanies (450 MMf per day) from the Arizona/California border to operated within California; all supplies were reeived from Kern County, merging with the Kern River system, urrently the interstate ompanies at the State border. That hanged operating at about full apaity during peak periods but as with the ompletion of the Kern River and Mojave Pipeline low as 40 perent during other periods; and (3) Tusarora system into southern California in 1993 and the Tusarora Pipeline (110 MMf per day) from the northern California Pipeline system into northern California in However, Border to Reno, Nevada, whih began operations in 1995 even today, most servie within California is provided by (load fators are unavailable). Paifi Gas and Eletri Company and Southern California Gas Company, the two largest LDCs in the Nation. The two PG&E Transmission-Northwest had the largest expansion ompanies play dual roles as LDCs for their ore ustomers during the period, adding more than 870 MMf per day to its and open-aess transporters for major shippers, suh as system from the Canada/Idaho border to the northern industrial users and eletri utilities, within their respetive California border, a 55-perent inrease. While the system servie territories. They also serve as intrastate pipelines with urrently operates at about 90 to 95 perent apaity during interonnetions to the other LDCs serving the State. peak periods (ompared with 100 perent in 1990), the range Southern California Gas Company provides distribution serbetween high and low is only about 8 perentage points. vie in southern California. Paifi Gas and Eletri laims Northwest Pipeline Company (NWPL), whih also brings northern California as its servie territory but also serves as a Canadian supplies into the region, inreased its apaity by vehile to move some Canadian gas supplies to southern more than 240 MMf per day, adding greater bidiretional California. flexibility and redireting some of its flows to growing markets within its operational territory. NWPL s overall All of the pipelines entering the region, with the exeption of utilization level is higher than it was in The system Northwest Pipeline Company, terminate there as well. Eah operates at about full apaity during peak periods, although also has major ommitments in the region. For instane, of the rates fell as low as 54 perent during off-peak periods. 645 delivery and interonnetion points on the El Paso Natural Gas system, 341 are within the region and represented Expansions of the El Paso Natural Gas Company and 76 perent of the peak-day volumes delivered off its system Transwestern Pipeline Company systems during 1992 in 1995 (Figure 19). All of Paifi Gas Transmission s and 1993 provided greater aess to San Juan Basin 192 delivery points are within the region, with the system prodution. The El Paso system experiened an inrease of transporting 2.7 Bf on its peak day in 1996 (Table 1). 371 MMf per day, or 17 perent, while Transwestern s 92 system inreased by 680 MMf per day. The interstate pipeline ompanies within the region operated at an average utilization rate of about 66 perent in Deliverability Within the Region That was down from an 84-perent level in The differene reflets, to a large degree, the drop in apaity utilization on those pipelines bringing Southwest Region gas into California: Transwestern Pipeline Company and El Paso Natural Gas Company. However, even during the summer months, these systems operate within a narrow range of apaity utilization. The States within the Western Region are almost totally dependent upon the interstate pipeline network for their gas supplies (Table 11). California is the only one that produes any substantial quantity, about 15 perent of its annual onsumption level (Appendix C, Table C2). Another important harateristi of the region is that loal gas distribution servies are dominated by a few large ompanies. Other than some small muniipal gas distributors, Idaho, Washington, and Nevada have only three LDCs, Oregon and Storage Deliverability Most of the underground storage failities in the Western Region, espeially in California whih has 91 perent of the region s working gas apaity, are used as market area supply reservoirs to store Canadian gas supplies, whih flow and are 92 Transwestern ompleted its San Juan expansion projet in 1996 and inreased apaity further in the area in Its ompletion expanded apaity on the New Mexio side of the basin, thus relieving a prodution onstraint situation that has hindered the flow of prodution out of the area for several years. The Transwestern system expansion prior to 1996 oinided 93, EIAGIS-NG Geographi with the onstrution of the Mojave Pipeline system, the two interonneting Information System, Natural Gas Pipeline State Border Capaity Database, as at the Arizona/California border. of Deember

84 reeived at a rather onstant rate (Appendix C, Table C1). The (38 perent in 1996), partiularly beause of the enhaned oil California storage fields are more like prodution (area) reovery (EOR) industry in southern California. The EOR storage loated at the market end of the supply orridor. The market, whih uses natural gas to generate steam for injetion availability of this storage is one of the reasons why the onto heavy-oil fields, aounts for about 200 Bf of the pipelines entering the region operate at suh high and natural gas entering the State during the year. The EOR sustained utilization rates. This storage allows the California market is the primary reason for the 3.6 perent annual operators to address the varying needs of their loal ustomers growth in the industrial setor in California sine 1993, when and shippers while maintaining a steady flow on their the Kern River and Mojave pipelines first entered this market. systems. Another fator in the growth in the industrial setor is the large number of ogeneration sites (more than 450) in the All the underground storage sites in the region are State. Natural gas aounted for more than 57 perent of the onventional reservoir storage, owned and operated by LDCs power generated from these failities in 1996 and onstituted (Table 10). Most of the storage is owned by the two largest about 12 perent of all eletri power generated in the State. California intrastate systems, PG&E and SoCal Gas. The rest is loated in Washington State and Oregon and is used for Residential ustomers have a 26-perent share of the seasonal storage and as peaking failities. California natural gas market, eletri utilities 18 perent, and ommerial ustomers only 13 perent (Appendix C, Despite the region s relatively temperate limate, LNG Table C3). Hydropower eletri generation is the major storage is also used by LDCs in the market, espeially in the ompetitor of natural gas in the State. In past years, for northern States of Washington and Oregon (Appendix C, instane, when severe drought onditions developed that Table C1). LNG as a peaking fuel is very ompatible restrited hydro-power generation, natural gas saw a major with the need for oasional supplemental supply support, gain in its use for eletri generation. As water levels espeially beause the geologi makeup of the region improved, however, natural gas lost its market advantage and, preludes muh further development of underground storage as a result, the use of natural gas for this purpose dropped by failities. Installation of LNG failities under these onditions 7.4 perent per year in the State from 1990 through also lessens the need for additional and expensive pipeline apaity when inremental supplies are needed only for the Nonetheless, the eletri utility industry remains a signifiant short term. user of natural gas. In three of the six States in the region (Arizona, Nevada, and California), the eletri utility industry End-Use Consumption aounts for 16 to 38 perent of total natural gas deliveries to onsumers (Appendix C, Table C3). From 1990 through 1996, gas-fired eletri generation apaity in the region grew at an annual rate of only 0.3 perent, 5.6 perent in Oregon and 3 perent in Nevada. Natural gas onsumption in the Western Region inreased at an average annual rate of about 4 perent between 1990 and 1996, whereas overall energy output inreased at only a 0.3 perent rate (Table 11). The slowdown in the regional eonomy during the early 1990s was the main fator in the dereased energy growth. The higher growth in natural gas onsumption an be attributed to its use as a substitute for hydropower when water levels were low and to its inreased use for enhaned-oil-reovery operations in California. Environmental ditates also brought about inreased substitution of natural gas for less lean-burning fuels. 94 Consumption by California ustomers aounts for 59 perent of the energy onsumed in the region and 74 perent of the natural gas. In 1995, 26 perent of the total energy onsumed in California was natural gas (Appendix C, Table C2). The industrial setor dominates the California gas market In the northern States of the region Idaho, Oregon, and Washington the industrial segment is the predominant user of natural gas, aounting for more than 48 perent of the natural gas market in eah State. Average annual industrial onsumption of gas in these States inreased by about 6.9 perent between 1990 and 1996, while the ommerial and eletri utility setors saw a derease in natural gas market share. These three States also showed some of the largest gains in overall energy onsumption throughout the period. The low usage of natural gas in these States for eletriity generation is primarily beause of their extensive hydroeletri apaity. Reent and Proposed Expansions Coinidently, Federal and State environmental regulations are 94 enouraging more natural gas use, partiularly in appliations where petroleum produts and oal dominate the market. In some parts of the region, regulations to limit atmospheri emissions may make natural gas the only fossil fuel that an be used for eletri power and steam generation. In 1997, two projets were ompleted in the region a 25- MMf-per-day export rossing with Mexio and a 12-MMfper-day pipeline expansion from Nevada to California. No new apaity has been built into the region sine

85 However, the growing eonomies of the northern States in the region Idaho, Oregon, and Washington may inrease apaity needs. The two major interstate pipeline ompanies serving these States, Paifi Gas Transmission and Northwest Pipeline, have announed plans to add additional deliverability during the next several years, although the final levels have yet to be determined. Outlook It appears that most, if not all, natural gas onsumer markets in the United States have adequate servie to meet their unique needs. Interstate pipeline apaity into eah of the six regional markets has inreased sine 1990 at a pae onsistent with the growth in demand. Furthermore, proposals for expanding the network are in line with urrent projetions for regional natural gas demand growth during the next several years. 95 Open-season exerises onduted by the initiators of the urrent inventory of expansion proposals have resulted in bids for future apaity sometimes in exess of what had been initially offered as a projet expansion estimate. This would seem to indiate that bidders/planners within loal markets also believe that demand will grow substantially during the next several years. Planners at the loal level usually possess better knowledge of the ustomer profiles within their own areas and, therefore, their bids for future pipeline apaity an be viewed as relatively firm support for the expansions. In some ases, however, these bids for apaity are being made by marketers and other parties who are not that intimately involved in the loal market but want to ensure their aess to new apaity in the future. This new apaity would provide them with alternative routes to meet their ustomers desires for aess to least ost supplies rather than to address demand growth. If all the projets urrently proposed were built and that is highly unlikely sine several have targeted the same markets interregional apaity would inrease by as muh as 14.7 Bf per day, or about 17 perent, from the 1996 level. Additional projets that are limited to providing servie within a speifi region omprise another 15.3 Bf per day of apaity. Underground storage operations, whih failitate both market enter servies and effiient pipeline operations, will also be expanding signifiantly over the next several years, many in 96 support of market enter or pipeline expansion. For instane, the implementation of the proposed Vetor pipeline, from Chiago to Dawn, Ontario, via the U.S. Midwest, will require the expansion of several storage failities in Ontario and in Mihigan to serve its shippers. Likewise, in the southern States of Texas, Louisiana, and Mississippi, where a number of market enters are loated, inluding the Henry Hub, a number of high-deliverability salt avern storage failities are being built or expanded to handle growing prodution out of the Gulf of Mexio and inreasing business between regional hubs suh as those loated in the Midwest (Chiago) and the Northeast (Pennsylvania and New York). In these States alone, proposed (through 2001) inreases in daily deliverability from storage sites that diretly or indiretly support market or trading enters amount to 2.2 Bf per day, or 5 perent more than urrent levels. The servies and flexibility offered at natural gas market enters an be expeted to be expanded and improved. The Chiago market enter, for example, should grow as Canadian import and Southwest supplies (via the Henry Hub) expand into the area and muh of this gas is redireted to the Northeast Region. The Leidy hub in Pennsylvania is the transation and transfer point for several market enters serving the Northeast and an be expeted to beome key to moving gas from the Midwest to New England markets and other parts of the Northeast. 95 Nevertheless, lose srutiny and detailed eonomi analyses by regulatory authorities will result in some projets being deemed unneessary 96 and thus not approved. The analyses are done in an effort to avoid, as muh, U.S. Underground Storage of as possible, the burden of osts to future ratepayers that are assoiated with Natural Gas in 1997: Existing and Proposed, Natural Gas Monthly, underutilized or unompleted projets. DOE/EIA-0130(97/09) (Washington, DC, September 1997). 79

86 5. Aess to Transportation Markets The physial apability of the U.S. natural gas pipeline This hapter provides a general piture of how shippers use network is only one part of transportation deliverability. Just the interstate transportation system and estimates the unused as important is the ontratual struture governing the flow of apability of the system, on the basis of data for a sample of gas along the network and the shipper s aess to pipeline 46 interstate pipeline ompanies that aounted for 97 perent apaity. Under Federal Energy Regulatory Commission of interstate transportation deliveries in The hapter (FERC) Order 636, whih was implemented in November examines how shippers reserve interstate pipeline apaity in 1993, market partiipants must make their own arrangements today s marketplae and identifies how muh apaity is for shipping gas. The ontrat serves as the servie agreement ontrolled by primary shippers holding firm ontrats. It also for the level, quality, loation (e.g., reeipt and delivery alulates apaity release levels to identify the portion of points), and prie for the transportation servie. reserved apaity that may be aessed on the release market. Sine the ownership of system apability does not neessarily Shippers an ontrat for several types of transportation indiate utilization, the volume of gas transported under firm servies, inluding high-quality firm servies, suh as firm and interruptible servies is also studied to omplete the 97 transportation and no-notie servie, and those servies piture of transportation market aessibility. subjet to disruption, suh as interruptible transportation and 98 released apaity subjet to reall. The types of servies Other parts of the interstate natural gas delivery system an seleted depend on the purpose for whih the gas is being also influene the level of a ustomer s reliane on the moved. For example, a loal distribution ompany responsible transportation market, suh as the type and availability of for supplying the gas needs of residential and ommerial storage and hub servies. While these servies may ustomers is likely to have a greater share of its transportation supplement transportation servies, they annot fully under firm ontrats than an industrial shipper that an use substitute for supply-to-market transportation of natural gas. interruptible servie or easily swith to an alternative fuel. Therefore, the fous of this hapter is on the servies used for long-haul transportation. In the hapter, apaity and apaity The value of a partiular type of transportation servie to a trading are measured on a heat ontent or Btu basis to be shipper will depend on where and when it is available, its onsistent with the units generally used in natural gas ost, and how it fits into the shipper s overall portfolio of ontrats. servies. If a shipper needs to have natural gas delivered to a partiular point next week, it would ontrat for servie along a line that has the apaity and servies available to make that delivery. Similar servies along a pipeline segment in another Estimating Capaity Availability area or for a different time period would not have the same value to the shipper. The availability of eah type of transportation servie depends on the physial apability of the pipeline network, how muh of that apaity is reserved by shippers, the terms and types of the ontrats in plae, and the extent to whih urrent ontrat holders use the system. 99 All of these fators must be onsidered when assessing the overall deliverability of the pipeline transportation system. 97 No-notie servie is generally a ombination of firm transportation and storage servies used to re-reate the quality of servie that ustomers previously reeived through pipeline ompany sales servie (see Glossary). It allows shippers to use their full apaity ommitment without advaned sheduling. 98 About 40 and 35 perent of the released apaity during the 1996 nonheating season and heating season, respetively, were not subjet to reall and thus may be onsidered high-quality firm servie. 99 If urrent apaity holders do not nominate to the pipeline to use their apaity (see p. 81), the pipeline ompany may offer the unused apaity to other shippers. A question that is often raised is how muh of the existing pipeline transmission apaity is available to meet additional firm servie demand. In this analysis, the estimated available apaity (unused firm servie apability) of the urrent system to transport natural gas is onsidered the sum of the amounts of unreserved apaity, unused released apaity, and unused firm ontrated apaity. The total apability of the system an be divided between the reserved or ommitted apaity and the unsubsribed apaity. A subset of the reserved apaity an be identified as apaity released to other shippers. Although a signifiant amount of pipeline apaity is used throughout the year, some remains unused. The relationship between apability and utilization is illustrated in Figure 20. This partiular example is not derived from atual information and may not resemble the sale of servies, apaity, and utilization on any speifi pipeline system. However, the hapter uses the onepts displayed in Figure 20 to analyze shippers ability to aess transportation servies on a regional and systemwide basis. 79

87 Figure 20. Relationship of Capaity and Utilization Capaity Utilization Total Capability Unsubsribed Capaity Firm Contrated Capaity Released Capaity Unommitted and Unused by Firm Shippers Released but Unused by Firm Shippers Released Capaity Used by Firm Shippers Firm Contrated Capaity Used by Firm Shippers Estimated Available Capaity Utilized Capaity Committed but Unused by Firm Shippers Note: A firm shipper is one using firm transportation servies. Soure:, Offie of Oil and Gas. The maximum apability of the pipeline system is used in this uniform data on peak-day and monthly transportation were analysis as the basis against whih all other variables are available for eah ompany. The estimated maximum measured to determine aessibility. The analysis uses a apaity of eah ompany was determined by hoosing the slightly different approah to determine maximum apability largest reported amount from the group of four soures of than that of Chapter 3, whih estimates pipeline apaity on apaity information used in this analysis (see the basis of design throughput apability at State border 102 Transportation System Aess, Appendix D). A pipeline 100 rossings. This hapter onsiders maximum apability to be ompany was onsidered to be loated in the region in whih the ability of the system to satisfy the maximum market it delivered the most gas. demands at the pipeline system delivery points. This measurement assumes that if a demand an be met at the The sample pipeline ompanies have a total maximum delivery point, then the transportation system an move that apability of 127 trillion Btu per day (Table 14). Thus, 101 volume of gas. theoretially, they ould deliver more than 46 quadrillion Btu of gas annually, or almost 1.6 times the total gas transported In the analysis, the maximum transportation apability of the by major interstate pipeline ompanies in While this interstate pipeline system is estimated on the basis of apaity figure may provide a relatively good estimate for maximum data for a sample of 46 major pipeline ompanies that apability, the extent to whih shippers reserve and use this aounted for 97 perent of interstate transportation deliveries apaity provides a better indiation of its availability. in The sample was seleted to ensure that adequate and 100 Chapter 3 disusses the apability of pipeline systems to move gas from prodution to market areas. Therefore, system apability is estimated by measuring the amount of natural gas that an flow aross State borders in a given day to determine the utilization of interregional transportation. It inludes data only for those pipeline segments that reported gas flow. 101 It should be noted that most pipeline ompanies systems handle loads through a series of reeipt and delivery points and that all gas reeived by the pipeline does not enter at a single point. Nor does a pipeline ompany deliver all its ustomers maximum demands on the same day. 102 Several soures of information are used to develop a piture of transportation apability and use, inluding: annual apaity reports and aompanying Format 567, System Flow Diagrams, filed annually with the Federal Energy Regulatory Commission (FERC) by major interstate pipeline ompanies under 18 CFR and 260.8; FERC Index of Customers filing; FERC Form 2, Annual Report of Major Natural Gas Companies ; FERC Form 11, Natural Gas Pipeline Company Quarterly Statement of Monthly Data ; and, Offie of Oil and Gas, Capaity Release Awards dataset. See Appendix D for more detailed information on data soures. 80

88 Table 14. Reserved Firm Transportation Capaity by Region, July 1996 and January 1997 Firm Transportation Contrats As of July 1, 1996 As of January 1, 1997 Conentration Conentration Maximum Capability Capaity Ratio Capaity Ratio Region (trillion Btu per day) (trillion Btu per day) (perent) (trillion Btu per day) (perent) Central Midwest Northeast Southeast Southwest Western U.S. Total Note: Totals may not equal sum of omponents beause of independent rounding. Soures: (EIA), Offie of Oil and Gas, derived from pipeline ompany reports filed with the Federal Energy Regulatory Commission (FERC): 1996 Peak-Day Capaity Report (18 CFR ); Index of Customers (April 1, 1996 April 1, 1997); Format FERC 567, System Flow Diagrams (1995); and FERC Form 2, Annual Report of Major Natural Gas Companies (1996). Transportation Market Ativity Shippers must first obtain apaity to effetuate movement of gas on a pipeline system. Therefore, all shippers must have aess to the firm or interruptible apaity markets to meet their needs. There are three ways in whih a shipper an obtain pipeline transportation servie: 103 Contrat for firm transportation servie. The shipper reserves a speifi amount of apaity via a ontrat with the pipeline ompany. Contrat for interruptible transportation servie. Capaity that is not ommitted to firm transportation servie or apaity that remains unused by the holder of firm transportation apaity may be offered by the pipeline as interruptible servie. These ontrats are typially for short periods of time. Changes in market onditions affet the size and availability of interruptible servie. Obtain apaity via the apaity release market. A shipper with unused apaity for firm transportation servie may hoose to trade that apaity on the release market. The releasing shipper may or may not subjet the apaity to reall, thereby making the servie quality similar to interruptible or firm transportation servie. One a shipper has a right to use apaity, it nominates, in writing or eletroni form, the daily amount of gas it wants to be reeived, delivered, or stored by the pipeline ompany. The shipper nominates apaity at speifi reeipt and delivery points along the pipeline system. The nomination of daily volumes may be renewed or hanged on a monthly, daily, or intraday basis and may be for any quantity up to the maximum daily quantity (MDQ) speified in the ontrat. Next, the pipeline ompany onfirms eah shipper s nomination and inquires into any needed hanges. Beause there are many shippers making nominations, the pipeline ompany must look at the aggregate quantities and determine whether the pipeline system an tolerate the overall level of nominations during the onfirmation proess. One the pipeline ompany asertains that the system an handle all shipper nominations, it shedules the gas, speifying gas flows in and out of eah reeipt and delivery point. The pipeline ompany determines priorities based upon type of servie. For example, firm servie will be sheduled ahead of interruptible servie. During the heating year (the 12 months ended Marh 31, 1997), on average 78 perent of physial apaity was ommitted to firm transportation ontrats, aording to pipeline ompany information filed with the Federal Energy Regulatory Commission. Although the amount of reserved apaity hanges over time, partiularly as the seasons hange, the share of physial apaity ommitted to firm transportation servie remained fairly onstant during 1996 and A portion of the firm apaity, approximately 20 perent, was traded during the year to replaement 103 Inludes firm transportation servie and no-notie servie. 81

89 104 shippers via the apaity release market. Interruptible servie aounted for 16 perent of transportation throughput during the heating year Ativity in primary firm apaity markets, whih inlude 107 firm transportation, no-notie servie, and sales servie, has generally inreased during the years sine industry 108 restruturing under FERC Order 636. Sine 1992, the volume of gas transported using firm servies has grown at an average rate of 9 perent per year. Transportation under firm servies inreased from 11.5 quadrillion Btu in 1992 to 16 quadrillion Btu in Sine its ineption in 1993, the apaity release market has also grown dramatially. Although release ativity delined slightly in 1996, it still represented 16 perent of the gas delivered for market at 3.6 quadrillion Btu. Unlike the firm and release markets, the interruptible transportation market has onsistently delined sine In 1996 only 2.9 quadrillion Btu was moved by interruptible transportation ompared with 8.3 quadrillion Btu in On the surfae these results might imply that apaity markets are getting tighter, thus, squeezing out the nonfirm apaity market. However, transportation ativity under various servies provides only part of the story behind transportation market aessibility. In addition to throughput levels, the pipeline system s level of unsubsribed apaity must also be onsidered. For example, a pipeline system may have enough exess apaity to reate a disounted firm transportation servie that ompetes with interruptible transportation. Likewise, deliverability on the U.S. pipeline system is as muh a produt of availability as it is physial apaity. All the physial spae on a pipeline system may be reserved under ontrat (fully subsribed), but if the reserved spae is not in use by the firm shipper, it may be aessed by another shipper using interruptible or short-term firm servie offered by the pipeline ompany. The underutilization of the pipeline system may also promote a strong market for released apaity. Therefore, all of these omponents should be reviewed to haraterize the availability and aessibility of various transportation servies. 104 Inludes apaity subjet to reall and that not subjet to reall. 105 Based on information ompiled by the Energy Information Administration from FERC Form 11, Natural Gas Pipeline Company Quarterly Statement of Monthly Data (1996). 106 Primary refers to firm servie obtained diretly from the pipeline ompany. 107 The volume of gas moved under pipeline ompany sales servie has been virtually zero sine Interstate Natural Gas Assoiation of Ameria (INGAA), Gas Transportation Through 1996 (May 1997). Firm Transportation Servie As previously disussed, most gas deliveries in 1996 were under firm transportation ontrats. Shippers may elet to ontrat for firm transportation servie on an annual or seasonal basis. With a firm transportation ontrat, the shipper may reserve, what it estimates to be, the highest demand it will inur on the pipeline system on any given day. 109 Correspondingly, the pipeline ompany agrees to make that amount of apaity available to the shipper on a daily basis. Pipeline ompanies dislose the amount of apaity reserved by eah firm ustomer in the quarterly Index of Customers filing to the FERC. For eah firm ontrat that is effetive the first day of the alendar quarter, pipeline ompanies are required to provide: the name of the shipper, the amount of apaity reserved, the rate shedule under whih servie is provided, the beginning and ending dates of the ontrat, and whether the ontrat ontains a rollover lause. The Index of Customers filing provides the measurement of the reserved portion of the pipeline ompany s system apaity. Data from these quarterly filings indiate that a large amount of pipeline apaity is reserved under firm ontrats (Figure 21). In fat, the reservation onentration ratios the perentage of maximum apability that is under a firm servie ontrat for the nonheating season (April through Otober) range from 76 to 86 perent in five of the six regions. The exeption lies in the Southwest Region, whih has a subsription rate of only 47 perent (Table 14). Subsription rates inreased signifiantly during the heating season in the Central (from 82 to 96 perent), Midwest (from 78 to 91 perent), and Northeast (from 76 to 84 perent) regions, while all other regions experiened little hange in reservation onentration between seasons. Conentration ratios in the Southwest are lower than in the other regions beause of the abundane of apaity on several prodution-oriented pipelines loated in the region. Exluding these pipeline ompanies from the analysis would inrease the onentration ratios in the Southwest from 47 to 73 perent for the nonheating season and from 49 to 77 perent for the heating season. However, removing these ompanies from the sample would not signifiantly alter the national onentration ratios; the ratios for the nonheating and heating seasons as well as the heating year would inrease by 3 perentage points to 79, 87, and 81 perent, respetively. 109 A few pipeline ompanies allow ustomers to elet different amounts of servie for the heating and non-heating seasons. This enables a heating load ustomer to subsribe to the required winter apaity without holding unneeded apaity in the summer. 82

90 Figure 21. Conentration of Reserved Firm Capaity by Region, April April Regional Capability (Perent) Central Midwest Northeast Southeast Southwest West Reserved Capaity Unsubsribed Capaity Note: Inludes ontrats for no-notie and firm transportation servies. Soures: (EIA), Offie of Oil and Gas, derived from pipeline ompany reports filed with the Federal Energy Regulatory Commission (FERC): 1996 Peak-Day Capaity Report (18 CFR ); Index of Customers (April 1, 1996-April 1, 1997); Format FERC 567, System Flow Diagrams (1995); and FERC Form 2, Annual Report of Major Natural Gas Companies (1996). Sine shippers base their ontrated amounts on 111 pipeline ompany eletroni bulletin board that it has their maximum demand for any given day, they will 112 available apaity. Interested parties then submit sealed frequently have unused apaity during the ourse of a year. bids to the pipeline ompany, whih evaluates the bids and In addition, the average prie of firm apaity tends to be high selets the winning replaement shipper based on seletion beause of the ost lassifiation and alloation methods used riteria approved by the releasing shipper. This mehanism by the Federal Energy Regulatory Commission to determine provides prospetive shippers aess to firm apaity that maximum transportation rates. Shippers pay to reserve otherwise may not have been available. apaity whether it is used or not. Primary firm shippers frequently release their unused apaity to mitigate the high The growth in the apaity release market indiates that reservation harges. shippers are embraing this apaity trading system. The amount of apaity held daily by replaement shippers has grown signifiantly sine the beginning of the apaity release Capaity Release Market market (Figure 22). The amount of apaity held by replaement shippers during the 12-month period ending The apaity release market, established under FERC Order Marh 1997 totaled 7.4 quadrillion Btu, a 22-perent inrease 636, provides shippers a method to resell unused apaity on over the previous 12-month period and almost double the 110 either a prearranged or open bid basis. Release transations level for the 12 months ending Marh 1995 (Figure 23). take plae when a primary shipper plaes a notie on the 111 FERC Order 587-B (Doket RM ) required that pipeline ompanies begin offering apaity release and other transations through their 110 Releasing shippers have the option of (1) prearranging a release for 1 Internet sites by June month or less or for any length of time at maximum osts, or (2) posting a 112 A primary shipper may release all or part of its apaity on a long-term notie of apaity availability on the pipeline ompany s eletroni bulletin or short-term basis and reeive redit from the release to its pipeline ompany board for open bidding. aount. 83

91 Figure 22. Growth in the Capaity Release Market, November Marh Index (November 1, 1993 = 1) Ative Contrats Capaity Held 0 NovJan Jan Jan Jan Soure:, Offie of Oil and Gas, derived from: November July 1994: Pasha Publiations, In. July Marh 1997: Federal Energy Regulatory Commission, Eletroni Data Interhange (EDI) data. Figure 23. Capaity Held by Replaement Shippers, by Region and Heating Years, Capaity Held (Quadrillion Btu) Months Ended Marh Central Midwest Northeast Southeast Southwest West Soure:, Offie of Oil and Gas, derived from Federal Energy Regulatory Commission, Eletroni Data Interhange (EDI) data. 84

92 The ativity in the apaity release market provides a measure The West and Midwest regions also experiened signifiant of the reserved apaity that is unused by the primary shipper perentage inreases over their levels, although the and is of value to the replaement shipper. The most apaity amounts are less than those of the Northeast Region. omprehensive information available on the release market The amount of apaity held by replaement shippers in the onerns data on apaity that is awarded to replaement West during the heating year inreased by almost shippers. While atual utilization annot be aurately 50 perent over the level. The 50-perent inrease determined, a substantial amount of gas ould be transported was the result of an additional 542 trillion Btu of apaity by use of released apaity. For example, if all the apaity held in the West Region during The apaity held by held by replaement shippers (Figure 24) were fully utilized, replaement shippers in the Midwest Region in perent of the 20.4 quadrillion Btu of gas delivered to inreased by 280 trillion Btu, or 43 perent over the onsumers during the 12 months ended Marh 31, 1997, level. ould have moved under released apaity. In ontrast to the Northeast, West, and Midwest regions, the 113 The amount of apaity held by replaement shippers Central and Southwest regions experiened delines in generally delines during the heating season, but it still apaity release ativity. In the Central Region, the amount of represents a sizeable amount. Based on apaity held, apaity held by replaement shippers dereased by 9 perent replaement shippers ould have moved 28 perent of the (128 trillion Btu) from the heating year level and the 10.4 quadrillion Btu of gas delivered to onsumers during the number of apaity awards dereased by 52 perent heating season by using released apaity. These (1,911 fewer awards). While the delines in the Southwest levels of released apaity are not shared equally among all of were not as large as those in the Central in absolute terms, the U.S. regions. The Northeast, whih had 44 perent of the they still represented signifiant perentage redutions for the apaity held by replaement shippers, led other regions in regions (Figure 23). the amount of apaity awarded during the year ended Marh 31, 1997 (Figures 23 and 24). The Southwest had the least The redution in apaity release awards in ertain regions amount of apaity awards in a region; less than 1 perent of may not neessarily indiate a lak of available apaity in the apaity held by replaement shippers ourred on those regions. For example, in the past few years the pipeline ompanies that primarily serve the Southwest Region Southwest has experiened a series of apaity turnbaks in (Figure 24). Although the amount of apaity awarded varied whih primary shippers notified the pipeline ompanies of between the heating and nonheating seasons, the regional their intent to redue the amount of firm apaity reserved on proportion of apaity held by replaement shippers was the systems. While the settlements in these ases resulted in essentially the same as that for the 12-month period ended an alloation of the turnbak osts among the parties, muh of Marh the physial spae of the pipeline systems was no longer reserved. The shippers that turned bak the apaity would Data from April 1994 through Marh 1997 indiate that the not have as muh exess apaity to release on the market; apaity release market provides a signifiant amount of however, it would not affet the total apability on the aess to transportation servie in many areas of the United pipeline system. Sine this exess apaity is no longer States. However, these data do not indiate whether these reserved, shippers may be able to deliver more gas using levels of apaity awards will be sustained or inrease. There interruptible transportation servie. are indiations that the market for released apaity in some regions may be maturing while onsiderable growth may ontinue in other regions. For example, the Northeast Region, in addition to having the highest level of awarded apaity, is Interruptible Transportation Servie experiening substantial growth in the market for released apaity. The amount of apaity held in the Northeast inreased by 977 trillion Btu, or 44 perent, between the and heating years (Figure 23). The total volume of released apaity held by replaement shippers 113 during a season is the sum of the apaity effetive on eah day of the season. For example, if a 60-day ontrat for Z thousand ubi feet per day is effetive within a season, then the sum of apaity held for the season would inlude Z thousand ubi feet 60 times for that ontrat. If that 60-day ontrat were only effetive, for example, for the last 20 days of the season, then the sum for the season would inlude Z thousand ubi feet 20 times, and the sum for the next season would inlude Z thousand ubi feet 40 times for that ontrat. A look at the utilization of interruptible servie provides the perspetive needed to omplete an assessment of transportation deliverability. While amounts vary throughout the year and aross regions, interruptible servie represents a relatively onstant share of national transportation throughput (Figure 25). More than 4,700 trillion Btu (TBtu) of gas was transported by use of interruptible servie during the heating year (the 12 months ended Marh 31, 1997), representing 16 perent of the 29,135 TBtu total transportation throughput. 85

93 Figure 24. Capaity Held by Replaement Shippers During the Nonheating and Heating Seasons, by Region (Trillion Btu) 1996 Nonheating Season (April - Otober) Heating Season (November - Marh) Midwest 497 (11.3%) Central 829 (18.9%) Western 1,001 (22.8%) Southwest 29 (0.7%) Southeast 141 (3.2%) Midwest % Central 534 (18.0%) Western 556 (18.8%) Southwest 21 (0.7%) Southeast 113 (3.8%) Northeast 1,897 (43.2%) Northeast 1,309 (44.2%) Total = 4,395 trillion Btu Total = 2,960 trillion Btu Total Heating Year = 7,355 trillion Btu Soure:, Offie of Oil and Gas, derived from Federal Energy Regulatory Commission, Eletroni Data Interhange (EDI) data. Figure 25. Natural Gas Pipeline Throughput Under Firm and Interruptible Servie, January September 1997 Transportation Volume (Quadrillion Btu) Firm Interruptible Jan Apr Jul Ot Jan Apr Jul Note: Throughput volumes exlude natural gas transported for storage. Soure:, Offie of Oil and Gas, derived from Federal Energy Regulatory Commission, FERC Form 11, Natural Gas Pipeline Company Quarterly Statement of Monthly Data. 86

94 Even during the heating season, when apaity is more apt to Industrial ompanies (inluding independent power be onstrained, almost 2,000 TBtu, or 15 perent, of gas produers, ogenerators, and ommerial firms) moved under interruptible servie. The share of interruptible servie during the heating year varied aross regions Loal distribution ompanies (inluding intrastate from a low of 7 perent of total transportation in the West to pipeline ompanies and ombination eletri and natural a high of 49 perent in the Southwest. The signifiant use of gas utilities for whih natural gas is not the primary or interruptible servie learly indiates that it represents a alternative soure of fuel for generating eletriity) viable servie option for shippers. Based on a 100-perent load fator, interruptible servie represented an average daily Marketers apaity of about 13 TBtu per day for the sample pipeline ompanies. Interstate pipeline ompanies The future availability and use of interruptible servie will in Other (inluding produers, gatherers, and other large part depend on the ontrating praties of shippers. As ompanies). the transportation market matures, terms or lengths of ontrat agreements may beome shorter. The likelihood that ontrats Differenes between these types of shippers were then will be terminated upon reahing their expiration date will examined, fousing on the data for April 1, The depend largely on the type, options, and requirements of the findings inlude: shipper holding the ontrat. Loal distribution ompanies (LDCs) held the largest portion of firm apaity, 44 perent. This was more than twie that of the next largest portion held by eletri utilities. Charateristis of Firm Capaity Held by Different Types of Shippers Shippers will ontrat for firm pipeline apaity for different quantities and terms, depending on the purpose for whih the gas is being moved. For example, a loal distribution ompany that is responsible for supplying the gas needs of ore residential and ommerial ustomers is likely to have a greater share of its transportation under firm ontrats than an industrial shipper that an use interruptible servie or easily swith to an alternate fuel. As another example of how shipper s needs differ, an industrial ompany, with welldefined and steady requirements for natural gas, may have ontrats with longer terms than those of a marketer who values flexibility and needs to offer servie to many types of ustomers. To examine these and other harateristis of firm apaity, shippers were lassified aording to six different ategories: 114 Eletri utilities (inluding ombination eletri and natural gas utilities for whih natural gas is the primary or alternative soure of fuel for generating eletriity) Virtually all (96 perent) of the firm apaity was held under long-term ontrats (those with terms of 1 year or more). The average lengths of the long-term ontrats ranged from 6.7 years for marketers to 11.9 years for pipeline ompanies. Marketers held 75 perent of the firm apaity under short-term ontrats (those with terms of less than 1 year), while LDCs held the largest proportion of apaity under long-term ontrats, 46 perent. The average size of long-term ontrats varied widely, from 57.0 billion Btu per day per ontrat for pipeline ompanies to 7.6 billion Btu per day for industrial shippers. The greatest shares of total firm apaity were held in the Northeast (36 perent) and the Midwest (25 perent). LDCs held the largest proportion of firm apaity within eah region exept for the Western Region, where marketers held the largest share. The Index of Customers lists only the names of shippers without 114 identifying the ompany types. Thus, shipper types were identified by Energy Information Administration (EIA) staff by ross-referening shipper names with other information soures and through Internet searhes (see Appendix D). New ontrats that beame effetive April 1, 1996, through April 1, 1997, aounted for 31 perent more firm transportation apaity than was assoiated with ontrats that expired during the period. 87

95 Capaity and Contrat Terms Shippers held 101 trillion Btu per day of firm apaity on April 1, 1997, based on the sample of pipeline ompanies 115 examined in this analysis (Table 15). The sample inludes 63 interstate pipeline ompanies, 17 more than in the analysis of transportation system aess presented earlier in the hapter. LDCs aounted for the largest portion of this apaity, 44 perent (Figure 26), more than twie that of the next largest portion, 21 perent, whih was held by eletri utilities. Industrial ompanies had the smallest share of firm apaity, 5 perent, but industrial ompanies probably had indiret aess to more firm apaity than is implied by this statisti. As end users, industrial ompanies are likely to have had aess to other firm apaity through ontrats with marketers and LDCs or any of the other types of shippers listed. Consider that in 1996, 5.5 quadrillion Btu of natural gas onsumed by industrial ompanies was delivered under firm 116 ontrats. Assuming a 100-perent load fator, this is equivalent to an average of 15 trillion Btu per day. On April 1, 1997, industrial ompanies held just over 5 trillion Btu per day in firm apaity, whih is only about one-third the amount of atual firm onsumption in One must use aution when making diret omparisons between onsumption and apaity beause ompanies must often reserve apaity on different segments of a pipeline even though not all segments are used for every delivery of natural gas. Still, even this rough omparison shows that industrial ompanies use more firm gas supplies than an be provided through the firm apaity ontrats they own diretly. The relative shares of firm apaity held by shippers are similar whether it is the middle of the winter, when demand for natural gas for spae heating is high, or in the summer, when apaity is more readily available and a shipper ould more likely reeive interruptible servie. On January 1, 1997, LDCs held 43 perent of total firm apaity, and industrial users held only 5 perent (total firm apaity was 108 trillion Btu per day). On July 1, 1997, LDCs held 42 perent and industrials held 6 perent of firm apaity (whih totaled 94 trillion Btu per day). Almost all of the firm apaity held by shippers on April 1, 1997, 96 perent, was held under long-term ontrats (1 year or longer). The overall average length of these ontrats for all shippers was 9.1 years. The distribution of long-term apaity among the different types of shippers was almost idential to that of total apaity LDCs held the most, 46 perent, followed by eletri utilities, whih held 21 perent, and industrials held the least, 5 perent. The average lengths of these long-term ontrats were quite varied among the different types of shippers (Figure 27). Average terms ranged from 6.7 years for marketers, refleting their need for flexibility, to 11.9 years for pipeline ompanies. Pipeline ompanies held a relatively small amount of the total firm apaity, 6.6 trillion Btu, or 7 perent of the total. They typially reserve apaity on other pipeline systems to assist in the operational ontrol of natural gas flows on their own 117 systems. Most pipeline ompanies have had deades of experiene in moving large volumes of gas. Their apaity requirements are fairly stable over time and they are thus able to benefit from longer length ontrats. The average length of long-term firm ontrats held by LDCs, whih had the largest proportion of apaity, was 9.7 years. The haraterization of what type of shipper holds apaity hanges dramatially for short-term ontrats (less than 1 year long). Here, marketers held the overwhelming amount of short-term apaity, 75 perent. The next largest share was only 8 perent held by shippers in the Other ategory. Industrial ompanies again held 5 perent of apaity, but in this ase they were only the seond smallest group. Pipeline ompanies held no short-term apaity at all. The 6.6 trillion Btu per day of firm apaity held by pipeline ompanies was all long term. 118 The average length of short-term ontrats was 3.5 months and ranged from 2.2 to 4.0 months among the different types of shippers. Marketers, with the largest volume, have the longest average term and industrials, the shortest. Even with the predominant role played by marketers in the area of shortterm ontrats, marketers still had 81 perent of their total firm apaity of 17.5 trillion Btu per day under long-term ontrats as of April 1, There are seasonal variations in the average length of shortterm ontrats held by some types of shippers. For example, as of January 1, 1997, a date toward the middle of the heating season, both eletri utilities and marketers held short-term firm apaity ontrats that averaged just over 5 months in length, mathing the length of the heating season. As of 115 The 63 pipeline ompanies inluded in this sample are those ompanies that file Index of Customers (IOC) information with the Federal Energy Regulatory Commission for whih there was omplete and onsistent information for eah of the quarters from April 1, 1996, to April 1, This resulted in the exlusion of data for eight ompanies that file IOC information. 116, Natural Gas Annual 1996, DOE/EIA-0131(96) (Washington, DC, September 1997), Table Pipeline ompanies also retain ontrol over a ertain amount of apaity on their own systems for purposes of operational ontrol. These apaity amounts are not part of the data ontained in the Index of Customers beause pipeline ompanies are not onsidered to be shippers on their own systems. 118 Pipeline ompanies did hold short-term apaity ontrats in all the other 3-month periods examined for this study. 88

96 Table 15. Charateristis of Firm Contrat Capaity as of April 1, 1997, by Shipper a b All Contrats Long-Term Contrats Short-Term Contrats Shipper Type Capaity Number Average Capaity Number Average Capaity Number Average (trillion Btu of Term (trillion Btu of Term (trillion Btu of Term per day) Contrats (years) per day) Contrats (years) per day) Contrats (months) Eletri Utility Industrial LDC , , Marketer Other Pipeline Company NA Total , , a Long-term ontrats are for 1 year or longer. b Short-term ontrats are for less than 1 year. Other inludes produers, gatherers, and those shippers for whih a ategory ould not be determined. LDC = Loal distribution ompany. NA = Not available. Note: Totals may not equal sum of omponents beause of independent rounding. Soure:, Offie of Oil and Gas, derived from Federal Regulatory Energy Commission (FERC) Index of Customers. Figure 26. Share of Total Firm Capaity Held on April 1, 1997, by Type of Shipper (Capaity in Trillion Btu per Day) LDCs 44.2 (43.8%) Eletri Utilities 20.7 (20.5%) Industrials 5.5 (5.4%) Other 6.4 (6.3%) Marketers 17.5 (17.4%) Pipeline Companies 6.6 (6.5%) Total firm apaity is 101 trillion Btu LDC = Loal distribution ompany. Note: Sum of perentage does not equal 100 perent beause of independent rounding. Soure:, Offie of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of Customers. 89

97 Figure 27. Average Length of Long-Term Firm Contrats as of April 1, 1997 Eletri Utilities 10.5 Industrials 7.6 LDCs 9.7 Marketers 6.7 Other 9.1 Pipeline Companies 11.9 All Shippers Years LDC = Loal distribution ompany. Note: Long-term ontrats are for 1 year or longer. Soure:, Offie of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of Customers. April 1, 1997, the beginning of the refill season, the average When onsidering the long-term ontrats, LDCs held the length of short-term ontrats fell to 2.6 months for eletri greatest total amount of firm daily apaity, yet the average utilities and to 4.0 months for marketers (Figure 28). apaity per ontrat for LDCs was muh lower than for either pipeline ompanies or eletri utilities (Figure 29). The average length of short-term ontrats delined between Also, the average daily apaity of LDC ontrats, January and April beause of the inreased proportion of 17.7 billion Btu, was lose to, but still smaller than that of ontrats with terms of 1 month or less as the heating season ontrats held by both marketers and ompanies in the Other ended. For example, as of January 1, 1997, eletri utilities ategory. Pipeline ompanies held the highest apaity longdid not hold any short-term apaity under ontrats that were term ontrats, averaging 57.0 billion Btu per day per for terms of 1 month or less; however, as of April 1, 1997, ontrat. Even though pipeline ompanies held a relatively 38 perent of their total short-term apaity was under 30-day small proportion of total firm apaity, the large amount of ontrats. The situation is similar for marketers, who on apaity per ontrat may reflet their role as movers of large January 1, 1997, held only 6 perent of short-term apaity volumes of gas from produing to onsuming areas of the under ontrats for 1 month or less but held 25 perent of ountry. Eletri utilities held the seond highest apaity their short-term apaity under suh ontrats on April 1, ontrats, averaging 33.0 billion Btu per day per ontrat. The smallest ontrats, averaging 7.6 billion Btu per day eah, were held by industrial ompanies. Total apaity held by different types of shippers provides one view of the firm apaity market, but the average apaity per ontrat provides another view of the ontrating praties of firm shippers. For all types of shippers, the Regional Shipper Charateristis average amount of apaity under long-term ontrats is Shippers hold the most firm apaity in those regions with muh larger than under short-term ontrats, refleting the larger populations and older temperatures and that are general use of short-term firm apaity to meet inremental farthest away from both domesti and Canadian soures of loads or to meet unexpeted demand. supply the Northeast and the Midwest. LDCs, whih are 90

98 Figure 28. Average Length of Short-Term Firm Contrats, January and April 1997 As of January 1, 1997 As of April 1, 1997 Eletri U tilities Industrials LDCs Marketers Other Pipeline Companies a 3.0 All Shippers Months a Pipeline ompanies did not have any ontrats for short-term, firm apaity on April 1, LDC = Loal distribution ompany. Note: Short-term ontrats are for less than 1 year. Soure:, Offie of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of Customers. Figure 29. Average Firm Capaity per Contrat as of April 1, 1997 Eletri Utilities Industrials LDCs Long Term Short Term Marketers Other Pipeline Companies a 57.0 All Shippers Billion Btu per Day a Pipeline ompanies did not have any ontrats for short-term firm apaity on April 1, LDC = Loal distribution ompany. Notes: Long-term ontrats are for 1 year or longer. Short-term ontrats are for less than 1 year. Soure:, Offie of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of Customers. 91

99 often the only soure of natural gas for weather-sensitive 21.3 trillion Btu (TBtu), or 59 perent of regional firm daily residential and ommerial users, held the largest proportion apaity. This was nearly three times the 7.2 TBtu held by the of firm apaity in almost every region, sometimes far seond-plae eletri utilities in the Northeast. In the exeeding that held by the seond largest shipper in the Midwest, LDCs held 8.6 TBtu of firm daily apaity, or 34 region. Eletri utilities (whih inlude ombination eletri perent of the regional total. Marketers played a greater role and gas utilities) and marketers also tend to hold larger shares as holders of firm apaity in this region, having the seond of regional firm apaity ompared with other types of highest level, at 5.8 TBtu (23 perent of the regional total). In shippers. the Northeast, marketers held only 8 perent of regional firm apaity. Of the 101 trillion Btu per day in firm apaity held on April 1, 1997, the largest share, 36 perent, was held on pipelines The Central Region had the most uniform distribution of that deliver most of their gas in the Northeast Region. The ontrated apaity among the different types of shippers next largest share, 25 perent, was in the Midwest. These (Figure 30). In part, this may be beause the natural gas regions rank first and third, respetively, in terms of 1995 delivered in the region is destined for final delivery in the population (Table 11, Chapter 4) and they were the third and Midwest or Northeast rather than for onsumption within the seond oldest, respetively, in 1996 (Table 10, Chapter 4). region. The Central Region ats as a onduit of gas from Roky Mountain produers and for some imports from These two regions alone aounted for 58 perent of the total Canada. LDCs still held the largest share of regional firm residential and ommerial onsumption of natural gas in apaity, 29 perent, but shippers in the Other ategory, 1996 (Table 12, Chapter 4), and LDCs held the largest share whih inludes produers, held the third largest proportion, of firm apaity in both regions. In the Northeast, LDCs held 19 perent. Figure 30. Share of Regional Firm Capaity as of April 1, 1997, by Shipper for Seleted Regions (Capaity in Trillion Btu per Day) Eletri Utilities 3.6 (26.2%) Central Region LDCs 4.1 (29.3%) LDCs 3.3 (62.6%) Southeast Region Industrials 0.5 (3.6%) Pipeline Companies 0.8 Other (6.1%) 2.6 (18.6%) Marketers 2.3 (16.2%) Eletri Utilities 0.8 (15.9%) Industrials 0.6 (11.7%) Pipeline Companies 0.1 (1.9%) Other 0.2 (3.6%) Marketers 0.2 (4.3%) Total firm apaity is 14 trillion Btu Total firm apaity is 5 trillion Btu LDC = Loal distribution ompany. Soure:, Offie of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of Customers. 92

100 Figure 31. Capaity Under New and Expiring Firm Contrats, April 1, April 1, 1997 Short Term Long Term Eletri Utilities New Contrats Expiring Contrats Eletri Utilities New Contrats Expiring Contrats Industrials Industrials LDCs LDCs Marketers Marketers Other Other Pipeline Companies Pipeline Companies Trillion Btu per Day Trillion Btu per Day LDC = Loal distribution ompany. Notes: Short-term ontrats are for less than 1 year. Long-term ontrats are for 1 year or longer. Soure:, Offie of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of Customers. The Southeast Region had the greatest onentration of of shippers when it omes to ontrat expiration or the ontrated apaity assigned to a single type of shipper. The initiation of new ontrats, data from the Index of Customers 3.3 TBtu per day held by LDCs aounted for 63 perent of were examined for the 12-month period of April 1, 1996 the regional total and was approximately four times the 119 through April 1, During this time, new ontrats for amount held by the shippers in seond plae, eletri utilities 30.4 trillion Btu (TBtu) per day of firm transportation (16 perent). The high onentration of apaity held by apaity beame effetive, while ontrats aounting for LDCs may be aused by two irumstanes that exist in the 23.1 TBtu per day expired. Thus, newly ontrated apaity Southeast Region. First, many of the LDCs whose servie exeeded expiring apaity by 31 perent. Marketers areas are in the Northeast Region hold apaity on Southeast aounted for the largest shares of both new and expiring pipelines. Seond, the Southeast may not have implemented apaity, but the relative shares among the different types of retail unbundling initiatives to the same extent as other shippers varied, depending on whether the ontrats were regions. Thus, LDCs must ontinue to serve the majority of short- or long-term. ustomers needs. This would also explain the low share of firm apaity held by marketers in this region, only 4 perent. Marketers totally dominated short-term apaity under both new and expiring ontrats during the period (Figure 31). In ontrast, marketers held the largest proportion of firm Marketers aounted for 60 perent of the 15.0 TBtu per day apaity in the Western Region, 33 perent (4.8 TBtu per of new short-term firm apaity and for 59 perent of the day). The Western Region inludes California, where retail 15.7 TBtu per day of expiring apaity. The shippers with the unbundling began as early as In the West, eletri next largest share of new short-term apaity were the utilities held the seond highest proportion of firm apaity, pipeline ompanies, with 11 perent of the total. For the 27 perent, followed losely by LDCs with 26 perent. expiring ontrats, LDCs held the next largest share, whih was also 11 perent. New and Expiring Long-Term Contrats Contrat expiration is of partiular interest in the natural gas industry today. To see if there are differenes between types New ontrats are those that started any time from April 2, 1996, 119 through April 1, Expiring ontrats are those that ended any time from April 1, 1996, through Marh 31,

101 Capaity under new short-term ontrats was almost equal to that under expiring ontrats during the period, but for longterm ontrats, new apaity was more than double that under expiring ontrats. Thus, shippers showed a preferene for longer term ontrats as they inreased their holdings of firm transportation apaity during the period. New long-term ontrats aounted for 15.4 TBtu per day of firm apaity, while long-term ontrats for 7.5 TBtu of daily apaity expired. As with short-term ontrats, marketers held the largest shares of both new and expiring apaity under longterm ontrats, but both LDCs and eletri utilities also held signifiant shares of eah. Marketers held 4.8 TBtu per day of firm apaity under new long-term ontrats, 31 perent of the total. This new apaity was 56 perent more than that held by marketers under expiring ontrats during the period. LDCs held 4.2 TBtu per day of new apaity under long-term ontrats, aounting for 27 perent of the total. The new apaity held by LDCs was more than double that held under expiring ontrats. New apaity held by eletri utilities during the period was also more than double the amount held by these shippers under expiring ontrats. With 2.7 TBtu, eletri utilities held 18 perent of the new, long-term daily apaity that beame effetive during the period. Summary The unused apability of the interstate pipeline system for transportation servie appears to be substantial. Based on an estimated maximum system apability of 127 trillion Btu (TBtu) per day, on average, 37 perent or 47 TBtu per day of the pipeline system apability was unused during the heating year (Figure 32). Shippers using firm transportation servies aounted for an average of 67 TBtu of gas per day, utilizing only 53 perent of the system apability and only 67 perent of the reserved apaity during the heating year. This allowed interruptible shippers to move an average of 13 TBtu per day, whih represented 10 perent of the system apability. While 100 TBtu per day, or 78 perent of the system apability, was reserved during , 20 TBtu of that was released to other firm shippers. Figure 32. Reserved, Utilized, and Available Capaity for the Heating Year Capaity Unsubsribed Capaity (27 TBtu/d) Unommitted and Unused by Firm Shippers Utilization Estimated Available Capaity (47 TBtu/d) Total Capability (127 TBtu/d) Firm Contrated Capaity (100 TBtu/d) Released Capaity (20 TBtu/d) Released but Unused by Firm Shippers Released Capaity Used by Firm Shippers Firm Contrated Capaity Used by Firm Shippers Utilized Capaity (80 TBtu/d) Capaity Used by IT Committed but Unused by Firm Shippers TBtu/d = Trillion Btu per day. IT = Interruptible transportation servie. Note: A firm shipper is one using firm transportation servies. Soure:, Offie of Oil and Gas. 94

102 Transportation aess during the heating season was less than Whether these levels of unsubsribed and aessible apaity the 12-month average, but market onditions indiate that the remain unhanged in the future will largely depend on what system an support signifiant additional load during this happens when firm transportation apaity ontrats ome up period as well. On average, 31 perent or 39 TBtu per day of for renewal. If signifiant apaity is turned bak to the the pipeline system apability was unused during the system, shippers may respond by transporting more gas using heating season. An average of 75 TBtu of gas per day was interruptible servie. transported under firm transportation servies, utilizing 59 perent of the system apability and 70 perent of the As of April 1997, virtually all (96 perent) of the firm reserved apaity. Interestingly, interruptible servie apaity apaity was held under long-term ontrats (those with terms utilization during the heating season was at the same level as of 1 year or more), with loal distribution ompanies holding during the nonheating season, 13 TBtu per day. The amount the largest portion of firm apaity, 44 perent. The greatest of reserved apaity inreased to 107 TBtu per day during the shares of total firm apaity were held in the Northeast heating season, but 20 TBtu per day was still released to (36 perent) and the Midwest (25 perent). seondary shippers. 95

103 Appendix A State-to-State Natural Gas Pipeline Capaity and Usage Levels This appendix presents data on State-to-State apaity and more than one branh or mainline segment rossing to another usage levels for major interstate pipeline ompanies in 1996 State. In suh ases, data for the several points are ombined and the perentage hange between 1990 and The and summed rather than being separately identified in the table. appendix onsists of six maps and six tables, whih orrespond Data regarding any of these individuals points, if wanted, are to the six U.S. geographi regions used throughout the report available within the supporting database. (Alaska, the Distrit of Columbia, and Hawaii are not inluded). The six regions are defined and ordered as follows: (The data ontained in the tables may be downloaded from the s (EIA) Internet site in Central Region - Colorado, Iowa, Kansas, Missouri, either a spreadsheet or database format, or from EIA s FTP site Montana, Nebraska, North Dakota, South Dakota, Utah, at ftp://ftp.eia.doe.gov/pub/oil_gas/natural_gas/analysis_puband Wyoming. liations/deliverability/data. The format and data element definitions for the STBORDER database and spreadsheet an Midwest Region - Illinois, Indiana, Mihigan, Minnesota, be found in the EIAGIS-NG (see Appendix C) data ditionary Ohio, and Wisonsin. DATADICT. DBF, also available from these sites.) Northeast Region - Connetiut, Delaware, Maine, For eah adjoining State, a summary line displaying the Maryland, Massahusetts, New Hampshire, New Jersey, ombined total apaity, 1996 average daily flows, and the New York, Pennsylvania, Rhode Island, Vermont, weighted average usage rate of all pipelines exiting the State is Virginia, and West Virginia. listed. Similarly, a summary of all pipeline routes entering the reeiving State is presented for eah of these values. In some Southeast Region - Alabama, Florida, Georgia, ases, no flow data were reported in 1996 for a known State-to- Kentuky, Mississippi, North Carolina, South Carolina, State pipeline ombination. In these ases, the apaity value and Tennessee. for the route is not inluded as part of the denominator (weighting fator) when average utilization rates at the State Southwest Region - Arkansas, Louisiana, New Mexio, and regional summary levels were alulated. Oklahoma, and Texas. The measure of apaity that is shown represents an estimate Western Region - Arizona, California, Idaho, Nevada, of the maximum throughput apability of the interstate natural Oregon, and Washington. gas pipeline network at a regional or State boundary. Speifially, it is an estimate of how muh gas an be Eah regional map portrays the States inluded in the region transported under normal operating onditions for a sustained and the approximate routes of the major interstate pipelines period of time. Information on apaity levels for the interstate operating in the region. Routes of some of the smaller pipeline pipeline systems was ompiled by using data available from systems are not displayed beause they are diffiult to filings at the Federal Energy Regulatory Commission (FERC) distinguish from the major systems. Underground storage site and through ontats with the ompanies themselves. loations are inluded in the maps to give the reader a perspetive on the proximity and aessibility of storage to The average daily flow volumes presented in Tables A1 pipelines within a region. Although the maps do not inlude through A6 are based upon 1996 data extrated from Form apaity levels, the reader an find a mapped regional State-to- EIA-176, Annual Report of Natural and Supplemental Gas State apaity summary representation in Chapters 3 and 5 of Supply and Disposition. They are the sum of data that an be the report. identified as volumes brought aross a border. The data on Form EIA-176 are annual; average daily levels were omputed Eah table represents one region, with the States within the on a 366-day basis (1996 was a leap year). More information region presented in alphabetial order. For eah State, a line on how Form EIA-176 data were ompiled and inluded in this item is listed for eah interstate pipeline ompany apable of report an be found in Appendix D. transporting gas from an adjoining State. It should be noted that in a number of instanes a pipeline ompany may have 97

104 Figure A1. Major Interstate Natural Gas Pipelines in the Central Region Soure: (EIA), EIAGIS-NG Geographi Information System, as of Deember

105 Table A1. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Central Region, by State, 1990 and 1996 (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Colorado Colorado Interstate Gas Kansas Kansas 244 Panhandle Eastern P L Co None Total KN Interstate Gas Co Nebraska Kansas/NE 60 Trailblazer Pipeline Co Nebraska 500 Total Transwestern Pipeline Co New Mexio New Mexio 500 Colorado Interstate Gas Oklahoma Oklahoma 250 Colorado Interstate Gas Utah 165 d Wyoming 180 Northwest Pipeline Corp Utah 587 Questar P L Co None Total Colorado Interstate Gas Wyoming Oklahoma 250 Questar P L Co None Williams Natural Gas Co Kansas 186 Wyoming Interstate Co None Total 1, , Total 3, , Iowa Northern Border Pipeline Co Minnesota 1, , None ANR Pipeline Co Missouri Illinois 603 Nat Gas P L Co of Ameria Nebraska 1, , Illinois 1,665 Northern Natural Gas Co 1, Minnesota/IL/SD 2,035 Total 2, , Total 4, , Kansas Colorado Interstate Gas Colorado Colorado 340 KN Interstate Gas Co Nebraska 81 Williams Natural Gas Co Nebraska 6 Total KN Interstate Gas Co Nebraska None ANR Pipeline Co Oklahoma Nebraska 693 Nat Gas P L Co of Ameria 1, Nebraska 1,175 Noram Gas Transmission Co None Northern Natural Gas Co 1, Nebraska 2,050 Panhandle Eastern P L Co 1, Missouri 1,559 Transwestern Pipeline Co None Williams Natural Gas Co Missouri/OK 1,231 Total 5, , Total 5, , Missouri Assoiated Natural Gas Co Arkansas Arkansas 30 Mississippi River Trans Corp Illinois 590 Nat Gas P L Co of Ameria 1, , Illinois 1,650 Noram Gas Transmission Co None Texas Eastern Trans Corp Illinois 300 Total 2, , Mississippi River Trans Corp Illinois None 99

106 Table A1. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Central Region, by State, 1990 and 1996 (Continued) (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Panhandle Eastern P L Co Kansas 1, , Illinois 1,361 Williams Natural Gas Co None Total 2, , ANR Pipeline Co Nebraska Iowa 680 Williams Natural Gas Co Oklahoma None Total 6, , Montana Montana Power Co Canada Canada 6 Northern Border Pipeline Co 1, , North Dakota 1,480 Northern Natural Gas Co Canada 60 Total 1, , Williston Basin I P L Co North Dakota North Dakota 304 Colorado Interstate Gas Wyoming None Montana Power Co None Williston Basin I P L Co Wyoming 162 Total Total 2, , Nebraska KN Interstate Gas Co Colorado None Trailblazer Pipeline Co Colorado 500 Total ANR Pipeline Co Kansas Missouri 693 KN Interstate Gas Co Colorado 96 Nat Gas P L Co of Ameria 1, Iowa 1,330 Northern Natural Gas Co 2, Iowa/SD 1,365 Williams Natural Gas Co None Total 4, , KN Interstate Gas Co Wyoming None Trailblazer Pipeline Co Colorado 500 Total Total 5, , North Dakota Viking Gas Transmission Co Minnesota None Northern Border Pipeline Co Montana 1, , South Dakota 1,685 Williston Basin I P L Co Montana 268 Total 1, , Williston Basin I P L Co South Dakota None Total 1, , South Dakota Northern Natural Gas Co Iowa None Northern Natural Gas Co Nebraska None Northern Border Pipeline Co North Dakota 1, , Minnesota 1,655 Williston Basin I P L Co None Total 1, , Williston Basin I P L Co Wyoming None Total 1, ,

107 Table A1. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Central Region, by State, 1990 and 1996 (Continued) (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Utah Northwest Pipeline Corp Colorado Colorado 366 Questar P L Co Wyoming 269 Total Northwest Pipeline Corp Idaho Wyoming 360 Kern River Gas Trans Co Wyoming Nevada 750 Northwest Pipeline Corp Colorado 310 Questar P L Co Colorado 23 Total 1, , Total 2, , Wyoming Colorado Interstate Gas Colorado Colorado 625 Questar P L Co Utah 703 Trailblazer Pipeline Co Nebraska 500 Total Colorado Interstate Gas Montana None Williston Basin I P L Co Montana 188 Total Williston Basin I P L Co South Dakota None Northwest Pipeline Corp Utah Utah 310 Questar P L Co Colorado 312 Total Total 1, a Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. b Average usage rate is equal to the average daily flow derived by estimated apaity. Utilization omputation does not inlude apaity against whih no flow was reported. Bidiretion flow our on some or all of the pipeline ompany lines that ross the State border. The value shown represents the apaity, or sum of apaity, for only the flow in the diretion indiated. d Less than 0.5 perent and greater than -0.5 perent. -- = Not appliable, pipeline not in servie in 1990 and/or no flow reported in 1990 or Note: Totals may not equal sum of omponents beause of independent rounding. Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember

108 Figure A2. Major Interstate Natural Gas Pipelines Serving the Midwest Region Soure: (EIA), EIAGIS-NG Geographi Information System, as of Deember

109 Table A2. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Midwest Region, by State, 1990 and 1996 (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Illinois ANR Pipeline Co Indiana 1, Indiana 1,249 d Midwestern Gas Trans Co None Texas Gas Trans Corp None Total 1, ANR Pipeline Co Iowa Wisonsin 581 Natural Gas PL Co of Ameria 1, , Wisonsin 55 Northern Natural Gas Co Wisonsin 385 Total 2, , Trunkline Gas Co Kentuky 1, , Indiana 745 Mississippi River Trans Corp Missouri Missouri 695 Natural Gas P L Co of Ameria 1, , None Panhandle Eastern P L Co 1, , Indiana 1,573 Texas Eastern Trans Corp Indiana 400 Total 3, , ANR Pipeline Co Wisonsin None Total 11, , Indiana ANR Pipeline Co Illinois 1, None Natural Gas P L of Ameria None Panhandle Eastern P L Co 1, , Ohio 1,313 Texas Eastern Trans Corp Ohio 671 Trunkline Gas Co None Total 4, , ANR Pipeline Co Kentuky 1, , Ohio/IL 2,997 Midwestern Gas Trans Co Illinois 649 Texas Gas Trans Corp 1, , Illinois/OH 1,051 Total 3, , ANR Pipeline Co Mihigan 1, None ANR Pipeline Co Ohio Mihigan 1,470 Panhandle Eastern P L Co None Total Total 10, , Mihigan Bluewater Pipeline Co Canada Canada 250 ANR Pipeline Co Indiana 1, Indiana 1,417 Trunkline Gas Co None Total 2, , ANR Pipeline Co Ohio Indiana/OH Panhandle Eastern P L Co Canada 100 Total 1, Great Lakes Gas Trans Ltd Wisonsin 2, , Canada 1,980 Northern Natural Gas Co None Total 2, , Total 6, , Minnesota Central Pipeline Co Canada Canada 63 Great Lakes Gas Trans Ltd 2, , Wisonsin 2,100 Viking Gas Transmission Co Wisonsin/ND 431 Total 2, ,

110 Table A2. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Midwest Region, by State, 1990 and 1996 (Continued) (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Northern Natural Gas Co Iowa 1, Wisonsin 232 Northern Border Pipeline Co South Dakota 1, , Iowa 1,575 Northern Natural Gas Co Wisonsin None Total 5, , Ohio ANR Pipeline Co Indiana 1, , Mihigan/IN 1,250 Crossroads Pipeline Co None Panhandle Eastern P L Co 1, Mihigan 860 Texas Eastern Trans Corp None Texas Gas Trans Corp 1, None Total 4, , Columbia Gas Trans Corp Kentuky None Tennessee Gas Pipeline Co 1, , Pennsylvania 1,575 Texas Eastern Trans Corp 2, , West Virginia 2,740 Union Light Heat & Power Co Total 4, , CNG Trans Corp Pennsylvania None Columbia Gas Trans Corp None Total CNG Trans Corp West Virginia Pennsylvania 560 Columbia Gas Trans Corp West Virginia 11 Total 1, Total 11, , Wisonsin ANR Pipeline Co Illinois 1, Illinois 550 Natural Gas PL Co of Ameria None Northern Natural Gas Co Mihigan 125 Total 1, ANR Pipeline Co Mihigan None Great Lakes Gas Trans Ltd Minnesota 2, , Mihigan 2,100 Northern Natural Gas Co None Viking Gas Transmission Co None Total 2, , Total 5, , a Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. b Average usage rate is equal to the average daily flow derived by estimated apaity. Utilization omputation does not inlude apaity against whih no flow was reported. Bidiretion flow our on some or all of the pipeline ompany lines that ross the State border. The value shown represents the apaity, or sum of apaity, for only the flow in the diretion indiated. d Less than 0.5 perent and greater than -0.5 perent. -- = Not appliable, pipeline not in servie in 1990 and/or no flow reported in 1990 or Note: Totals may not equal sum of omponents beause of independent rounding. Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember

111 Figure A3. Major Interstate Natural Gas Pipelines Serving the Northeast Region Soure: (EIA), EIAGIS-NG Geographi Information System, as of Deember

112 Table A3. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Northeast Region, by State, 1990 and 1996 (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Connetiut Tennessee Gas Pipeline Co Massahusetts Massahusetts 80 Algonquin Gas Trans Co New York 1, Rhode Island 665 Iroquois Pipeline Co New York 260 Tennessee Gas Pipeline Co None Total 1, , Total 1, , Delaware Eastern Shore Nat Gas Co Maryland None Columbia Gas Trans Corp Pennsylvania New Jersey 141 Eastern Shore Nat Gas Co Maryland 10 Transontinental Gas P L Co None Total Total Maine Granite State Gas Trans In New Hampshire New Hampshire 31 Total Maryland Eastern Shore Nat Gas Co Delaware Delaware 28 CNG Trans Corp Pennsylvania Virginia 350 Columbia Gas Trans Corp None Eastern Shore Nat Gas Co None d Texas Eastern Trans Corp Pennsylvania 163 Total Columbia Gas Trans Corp Virginia 1, Pennsylvania 146 d Transontinental Gas P L Co 2,100 1, Pennsylvania 2,050 Total 3, , Columbia Gas Trans Corp West Virginia None Total 4, , Massahusetts Tennessee Gas Pipeline Co Connetiut None None Tennessee Gas Pipeline Co New York 1, NH/RI/CT 329 Algonquin Gas Trans Co Rhode Island Rhode Island 145 Total 1, , New Hampshire Granite State Gas Trans In Maine None Granite State Gas Trans In Massahusetts Maine 31 Tennessee Gas Pipeline Co None Total Granite State Gas Trans In Vermont None Total New Jersey Columbia Gas Trans Corp Delaware None Columbia Gas Trans Corp Pennsylvania None Tennessee Gas Pipeline Co New York 377 Texas Eastern Trans Corp 2, , New York 562 Transontinental Gas P L Co 2, , New York 885 Total 5, , Total 6, ,

113 Table A3. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Northeast Region, by State, 1990 and 1996 (Continued) (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 New York Empire Pipeline Co Canada None Iroquois Pipeline Co Connetiut 420 North Country P L Co St Lawrene Gas None Tennessee Gas Pipeline Co None Total 2, , Iroquois Pipeline Co Connetiut New York 250 Algonquin Gas Trans Co New Jersey 1, Connetiut 1,030 Tennessee Gas Pipeline Co Connetiut 121 Texas Eastern Trans Corp None Transontinental Gas P L Co None Total 2, , CNG Trans Corp Pennsylvania 1, None Columbia Gas Trans Corp Pennsylvania 1 National Fuel Gas Supply Co Pennsylvania 321 Penn York Energy Corp Pennsylvania 60 Tennessee Gas Pipeline Co Massahusetts 1,059 Total 2, , Total 8, , Pennsylvania Columbia Gas Trans Corp Maryland Delaware/NY/NJ 547 Transontinental Gas P L Co 2, , Maryland/DE/NJ 2,463 Total 2, , Transontinental Gas P L Co New Jersey 1, None Columbia Gas Trans Corp New York None National Fuel Gas Supply Co None Penn York Energy Corp None Total , CNG Trans Corp Ohio New York/MD 2,098 Tennessee Gas Pipeline Co 1, , New York/NJ 1,322 Total 2, , Carnegie Natural Gas Co West Virginia None CNG Trans Corp Ohio 435 Columbia Gas Trans Corp 1, Ohio/MD/WV 651 Equitrans In West Virginia 70 Texas Eastern Trans Corp 2, , New Jersey 2,850 Total 4, , Total 11, , Rhode Island Algonquin Gas Trans Co Connetiut Massahusetts 705 Algonquin Gas Trans Co Massahusetts None Tennessee Gas Pipeline Co None Total Total 1, Vermont Granite State Gas Trans In Canada New Hampshire 31 Vermont Gas Sys In None Total Total

114 Table A3. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Northeast Region, by State, 1990 and 1996 (Continued) (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Virginia CNG Trans Corp Maryland West Virginia 21 Transontinental Gas P L Co North Carolina 2, , Maryland/NC 2,520 East Tennessee Nat Gas Co Tennessee None Columbia Gas Trans Corp West Virginia 1, Maryland/NC 1,137 Total 4, , West Virginia Columbia Gas Trans Corp Kentuky 1, , Virginia/PA 3,121 Tennessee Gas Pipeline Co None Total 2, , Columbia Gas Trans Corp Maryland Columbia Gas Trans Corp Ohio None Texas Eastern Trans Corp 2, , Pennsylvania 2,625 Total 2, , Columbia Gas Trans Corp Pennsylvania OH/KY 938 Equitrans In Pennsylvania 255 Total CNG Trans Corp Virginia Ohio/PA 1,209 Total 5, , a Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. b Average usage rate is equal to the average daily flow derived by estimated apaity. Utilization omputation does not inlude apaity against whih no flow was reported. Bidiretion flow our on some or all of the pipeline ompany lines that ross the State border. The value shown represents the apaity, or sum of apaity, for only the flow in the diretion indiated. d Less than 0.5 perent and greater than -0.5 perent. -- = Not appliable, pipeline not in servie in 1990 and/or no flow reported in 1990 or Note: Totals may not equal sum of omponents beause of independent rounding. Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember

115 Figure A4. Major Interstate Natural Gas Pipelines in the Southeast Region Soure: (EIA), EIAGIS-NG Geographi Information System, as of Deember

116 Table A4. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Southeast Region, by State, 1990 and 1996 (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Alabama Koh Gateway Pipeline Co Florida None Mobile Bay Pipeline Co Gulf of Mexio None Alabama-TN Nat Gas Co Mississippi None Florida Gas Trans Co 1, Florida 1,475 Koh Gateway Pipeline Co Florida 145 d Southern Natural Gas Co 2,250 1, Georgia 1,530 Tennessee Gas Pipeline Co 1, , Tennessee 1,732 Texas Eastern Trans Corp 2, , Tennessee 2,151 Transontinental Gas P L Co 3, , Georgia 3,467 Total 11, , Total 11, , Florida Florida Gas Trans Co Alabama 1, , None d Koh Gateway Pipeline Co Alabama 20 Total 1, , South Georgia Nat Gas Co Georgia None Total 1, , Georgia South Georgia Nat Gas Co Alabama Florida 56 Southern Natural Gas Co 1, , South 332 Carolina/TN Transontinental Gas P L Co 3, , South Carolina 3,195 Total 5, , Southern Natural Gas Co South Carolina None East Tennessee Nat Gas Co Tennessee None Total 5, , Kentuky ANR Pipeline Co Tennessee 1, , Indiana 1,386 Columbia Gulf Trans Co 2, , West Virginia 1,680 Midwestern Gas Trans Co Indiana 663 Tennessee Gas Pipeline Co 2, , Ohio/WV 2,458 Texas Eastern Trans Corp 2, , Ohio 2,066 Texas Gas Trans Corp 1, , Indiana/TN 1,534 Trunkline Gas Co 1, , Illinois 1,799 Total 12, , Columbia Gas Trans Corp West Virginia Ohio/WV 2,254 Total 12, , Mississippi Koh Gateway Pipeline Co Alabama None ANR Pipeline Co Arkansas 1, , Tennessee 1,480 Tennessee Gas Pipeline Co 1, Tennessee 2,132 Texas Gas Trans Corp 2, , Tennessee 1,880 Trunkline Gas Co 1, , Tennessee 1,836 Total 7, , Chandeleur Pipeline Co Gulf of Mexio Columbia Gulf Trans Co Louisiana 1, , Tennessee 1,961 Florida Gas Trans Co 1, Alabama 1,375 Koh Gateway Pipeline Co 1, Alabama/LA 610 Mid-Louisiana Gas Co Louisiana

117 Table A4. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Southeast Region, by State, 1990 and 1996 (Continued) (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Southern Natural Gas Co 1, , Alabama 2,250 Tennessee Gas Pipeline Co 2, , Alabama 1,899 Texas Eastern Trans Corp 2, , Alabama 2,108 Transontinental Gas P L Co 3, , Alabama 3,302 Total 13, , Total 21, , North Carolina Transontinental Gas P L Co South Carolina 3, , Virginia 2,587 Columbia Gas Trans Corp Virginia None Transontinental Gas P L Co None Total 445 1, Total 3, , South Carolina Southern Natural Gas Co Georgia Georgia 50 Transontinental Gas P L Co 3, , North Carolina 3,002 Total 3, , Tennessee Tennessee Gas Pipeline Co Alabama 1, , Kentuky 2,671 Texas Eastern Trans Corp 2, , Kentuky 2,104 Total 3, , Southern Natural Gas Co Georgia None Texas Gas Trans Corp Kentuky None Alabama-TN Nat Gas Co Mississippi 91 1, None ANR Pipeline Co 1, , Kentuky 1,398 Columbia Gulf Trans Co 1, , Kentuky 2,010 Noram Gas Transmission Co Arkansas 25 Tennessee Gas Pipeline Co 2, , None Texas Gas Trans Corp 1, , Kentuky 1,669 Trunkline Gas Co 1, , Kentuky 1,825 Total 9, , Total 13, , a Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. b Average usage rate is equal to the average daily flow derived by estimated apaity. Utilization omputation does not inlude apaity against whih no flow was reported. Bidiretion flow our on some or all of the pipeline ompany lines that ross the State border. The value shown represents the apaity, or sum of apaity, for only the flow in the diretion indiated. d Less than 0.5 perent and greater than -0.5 perent. -- = Not appliable, pipeline not in servie in 1990 and/or no flow reported in 1990 or Note: Totals may not equal sum of omponents beause of independent rounding. Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember

118 Figure A5. Major Interstate Natural Gas Pipelines Exporting from the Southwest Region Soure: (EIA), EIAGIS-NG Geographi Information System, as of Deember

119 Table A5. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Southwest Region, by State, 1990 and 1996 (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a b Estimated Entering Capaity Average Daily Flow Average Usage Rate Exiting Capaity Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Arkansas ANR Pipeline Co Louisiana 1, , Mississippi 1,430 Mississippi River Trans Corp Missouri/LA 1,280 Noram Gas Transmission Co Missouri 100 Tennessee Gas Pipeline Co 1, Mississippi 1,580 Texas Gas Trans Corp 2, , Mississippi 2,163 Trunkline Gas Co 1, , Mississippi 1,852 Total 7, , Assoiated Natural Gas Co Missouri Missouri 10 Noram Gas Transmission Co Oklahoma 1,654 d 1, Louisiana/TX 206 Ozark Gas Trans Sys None Total 1, , Noram Gas Transmission Co Tennessee None Natural Gas P L Co of Ameria Texas 1, , Missouri 2,250 Texas Eastern Trans Corp Missouri 300 Total 2, , Total 11, , Louisiana Mississippi River Trans Corp Arkansas None Noram Gas Transmission Co Texas 25 Total ANR Pipeline Co d Gulf of Mexio 1,919 NA NA -- NA Columbia Gulf Trans Co 1,210 NA NA -- NA High Island Offshore Co 1,800 NA NA -- NA Koh Gateway Pipeline Co 530 NA NA -- NA Quivira Gas Co 120 NA NA -- NA Sea Robin Pipeline Co 1,595 NA NA -- NA Shell Gas Pipeline Co 600 NA NA -- NA Southern Natural Gas Co 2,012 NA NA -- NA Stingray Pipeline Co 1,170 NA NA -- NA Tennessee Gas Pipeline Co 2,755 NA NA -- NA Texas Eastern Texas Trans Co 990 NA NA -- NA ,700 NA NA -- NA ,226 NA NA -- NA Total 17,627 NA NA -- NA Koh Gateway Pipeline Co Mississippi None Mid-Louisiana Gas Co None Total Florida Gas Trans Co Texas Mississippi 1,340 Gulf States Transmission Corp None d Koh Gateway Pipeline Co Mississippi 1,030 Mississippi River Trans Corp Arkansas 1,340 Natural Gas P L Co of Ameria None Noram Gas Transmission Co Arkansas 825 Sabine Pipe Line Company None Southern Natural Gas Co Mississippi 1,661 Tennessee Gas Pipeline Co 1, , Mississippi/AR 4,101 Texas Eastern Trans Corp Mississippi 2,201 Texas Gas Trans Corp Arkansas 2,002 Transontinental Gas P L Co Mississippi 3,056 Trunkline Gas Co Arkansas 1,852 Total 5, , e ANR Pipeline Co Louisiana Arkansas 1,338 e Columbia Gulf Transmission Co Mississippi 2,133 e Natural Gas PL Co of Ameria Texas 509 e Transwestern Pipeline Corp Texas 199 Total 24, ,

120 Table A5. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Southwest Region, by State, 1990 and 1996 (Continued) (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a b Estimated Entering Capaity Average Daily Flow Average Usage Rate Exiting Capaity Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 New Mexio El Paso Natural Gas Co Colorado Arizona 650 Transolorado Gas Trans Co None Transwestern Pipeline Co Arizona 500 Total 1, El Paso Natural Gas Co Texas 2, Arizona 4,261 Natural Gas P L Co of Ameria Texas 720 Transwestern Pipeline Co Arizona 1,090 Total 4, Total 5, Oklahoma Colorado Interstate Gas Colorado Texas 200 KN Interstate Gas Co Kansas Texas 35 Natural Gas P L Co of Ameria Texas 750 Williams Natural Gas Co Missouri 496 Total ANR Pipeline Co Texas Kansas 853 Colorado Interstate Gas None El Paso Natural Gas Co None KN Interstate Gas Co None Natural Gas P L Co of Ameria 1, Kansas/TX 1,903 Northern Natural Gas Co 2, Kansas 1,330 Panhandle Eastern P L Co Kansas/TX 1,451 Transok In None Transwestern Pipeline Co Kansas 5 Williams Natural Gas Co Kansas 496 Total 5, , Total 6, , Texas Natural Gas P L Co of Ameria Arkansas None Noram Gas Transmission Co Louisiana 140 Total Blak Marlin Pipeline Co d Gulf of Mexio 384 NA NA -- NA Natural Gas PL Co of Ameria 115 NA NA -- NA Sea Rim Pipeline Co 176 NA NA -- NA Seagulf Interstate Corp 95 NA NA -- NA Superior Offshore Pipeline Co 360 NA NA -- NA Transontinental Gas PL Co 400 NA NA -- NA Total 1,530 Koh Gateway Pipeline Co Louisiana None Natural Gas P L Co of Ameria Arkansas 1,873 Noram Gas Transmission Co None Texas Eastern Trans Corp Louisiana 743 Total Texas Eastern Trans Corp Mexio None El Paso Natural Gas Co New Mexio 1, None Natural Gas P L Co of Ameria Oklahoma 1,765 Northern Natural Gas Co Oklahoma 2,500 Transwestern Pipeline Co Oklahoma 75 Total 3, , ANR Pipeline Co Oklahoma None Colorado Interstate Gas None El Paso Natural Gas Co New Mexio 2,750 KN Interstate Gas Co None Natural Gas P L Co of Ameria New Mexio

121 Table A5. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Southwest Region, by State, 1990 and 1996 (Continued) (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a b Estimated Entering Capaity Average Daily Flow Average Usage Rate Exiting Capaity Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Noram Gas Transmission Co None Northern Natural Gas Co 1, None Panhandle Eastern P L Co Oklahoma 389 Transok In None Transwestern Pipeline Co New Mexio 950 Total 2, Total 8, , e ANR Pipeline Co Texas Oklahoma 250 e Florida Gas Transmission Co Louisiana 300 e Mississippi River Transm Co Louisiana 85 e Southern Natural Gas Co Louisiana 93 e Tennessee Gas Pipeline Co Louisiana 1,153 e Texas Eastern Trans Corp Arkansas/LA 937 e Texas Gas Transmission Corp Louisiana 138 e Transontinental Gas Pipeline Co Louisiana 725 e Trunkline Gas Co Louisiana 334 e United Gas Pipeline Co Louisiana 830 e Williams Natural Gas Co Oklahoma 50 a Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. b Average usage rate is equal to the average daily flow derived by estimated apaity. Utilization omputation does not inlude apaity against whih no flow was reported. Bidiretion flow our on some or all of the pipeline ompany lines that ross the State border. The value shown represents the apaity, or sum of apaity, for only the flow in the diretion indiated. d List of Offshore-to-Onshore apaity levels is not all inlusive. In some ases apaity levels may be understated. e The pipeline, or a portion of the pipeline system, begins servie in the Reeiving State. Pipeline is shown here for purposes of showing apaity exiting the State. -- = Not appliable, pipeline not in servie in 1990 and/or no flow reported in 1990 or NA = Not available. Note: Totals may not equal sum of omponents beause of independent rounding. Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember

122 Figure A6. Major Interstate Natural Gas Pipelines Serving the Western Region Northwest Pipeline Co Paifi Gas & Eletri Gas Transmission Co - Northwest Tusarora Gas Transmission Co Paifi Gas & Eletri Gas Gas Transmission Co (Intrastate) Southern California Gas Co (Intrastate) San Diego Gas & Eletri Co (Intrastate) Paiute Pipeline Co Kern River Gas Transmission Co Southwest Gas Co (Intrastate) Mojave Pipeline Co Transwestern Gas Pipeline Co El Paso Natural Gas Co = Underground Storage Soure: (EIA), EIAGIS-NG Geographi Information System, as of Deember

123 Table A6. State Border Capaity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines Operating in the Western Region, by State, 1990 and 1996 (Volumes in Million Cubi Feet per Day) Transmission Throughput Capabilities and Flows a Average Usage Estimated Entering Capaity Average Daily Flow Exiting Capaity Rate b Perent Perent Perent Reeiving State/ Upstream Change Change Change Downstream Via Pipeline Company State State 1996 Arizona El Paso Nat Gas Co New Mexio 4, , California/NV/MX 3,679 Transwestern Pipeline Co 1, California 1,225 Total 5, , California El Paso Nat Gas Co Arizona 3, , None Mojave Pipeline Co None Transwestern Pipeline Co 1, None Total 5, , Paifi Interstate Offshore Co Offshore Calif None Kern River Gas Trans Co Nevada None Paiute Pipeline Co None Total 780 3, Paifi Gas Transmission Co Oregon 1, , None Tusarora Pipeline Co Nevada 95 Total 2, , Total 7, , Idaho Paifi Gas Transmission Co Canada 2, , Washington 2,632 Northwest Pipeline Corp Oregon , ,138 Nevada 158 Northwest Pipeline Corp Utah Utah 298 Northwest Pipeline Corp Washington None Total 3, , Nevada El Paso Nat Gas Co Arizona None Tusarora Pipeline Co California None Northwest Pipeline Corp Idaho None Kern River Gas Trans Co Utah California 750 Total 1, , Oregon Northwest Pipeline Corp Idaho Washington 941 Northwest Pipeline Corp Washington Idaho 481 Paifi Gas Transmission Co 2, , California 2,063 Total 3, , Total 3, , Washington Ferndale P L Co Canada None Northwest Pipeline Corp 1, Oregon 1,289 Sumas International Pl Co None Total 1, Paifi Gas Transmission Co Idaho 2, , Oregon 2,378 Northwest Pipeline Corp Oregon Idaho 122 Total 4, , a Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. b Average usage rate is equal to the average daily flow derived by estimated apaity. Utilization omputation does not inlude apaity against whih no flow was reported. Bidiretion flow our on some or all of the pipeline ompany lines that ross the State border. The value shown represents the apaity, or sum of apaity, for only the flow in the diretion indiated. -- = Not appliable, pipeline not in servie in 1990 and/or no flow reported in 1990 or Note: Totals may not equal sum of omponents beause of independent rounding. Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline State Border Capaity Database, as of Deember

124 Appendix B Natural Gas Pipeline and System Expansions, A great deal of new pipeline apability has been proposed for development throughout North Ameria between now and the turn of the entury. The most extensive development is foused on expanding the deliverability of Canadian gas to the U.S. Midwest and Northeast and to Canadian markets. Several new pipelines and system expansions are planned that not only would improve aess to natural gas supplies in Western Canada but also to prodution from the developing areas, suh as the Sable Island field in Eastern Canada. The seond-largest fous is on improving aess to the inreasing deep-water prodution in the Gulf of Mexio. Next are those projets whose objetives are to inrease the flow of lowerost supplies loated in the Central United States to markets loated primarily in the Midwest. Currently, the apability to do so is limited in some areas. The latter series of expansions will be ompeting, to some degree, with the projets slated to inrease flows of Western Canadian gas to the Midwest marketplae. Although there is a question as to whether or not the market an support all these expansions, it must be kept in mind that these projets an proeed only if suffiient ommitments are 120 entered into by future ustomers. Most of the proposed projets have, or are, undergoing market-testing through open-season offerings whereby potential ustomers have plaed bids for future apaity on the proposed projets. The planned apaity of the proposed projets usually reflets the results of these open seasons and indiates that, at least at the moment, loal distribution ompanies and other major ustomers believe demand will grow suffiiently to support the inremental supplies destined for these markets. This appendix examines expansions to the North Amerian natural gas pipeline network during 1997 and the nature and type of proposed pipeline projets announed or approved for onstrution during the next several years in the United States. It inludes those projets in Canada and Mexio that tie in with U.S. markets or projets. Additional details on some of the proposed projets and an analysis of their potential impat on a regional basis or on the overall North Amerian natural gas pipeline network may be found in the main body of the report. Overview At least 41 pipeline expansion projets were ompleted and plaed in servie in the United States during 1997 (Figure B1) representing more than 6.3 billion ubi feet per day (Bf/d) of added pipeline apaity. These projets either added apaity diretly to the interstate network, improved loal intrastate servie, or expanded aess to produing fields or natural gas market enters. Seven of the projets inreased interregional transmission apability by 750 million ubi feet per day (MMf/d): 513 MMf/d in the United States and 237 MMf/d into Mexio (Tables ES1 and B1). These projets, plus others, inreased overall daily interstate apability by a little more than 2 perent, or 4.6 Bf, whih is 121 double the interstate apaity added in Moreover, the total number of ompleted projets in the United States was substantially more than in 1995 (41 vs. 26). Almost all the natural gas pipeline projets slated for ompletion in 1997 were plaed in servie on shedule. 122 Two were aneled beause of hanges in market onditions or ompetitive pressures. A few others were postponed while their original designs were reevaluated in light of onditional regulatory approval or shifts in onstrution priorities. As of February 1998, the was traking more than 100 proposed pipeline expansions and new pipeline projets at various stages of development in the United States, Canada, and Mexio, with planned in-servie dates between 1998 and the end of 2000 (Figure B2). A number of these projets are slated to be phased in over several years or are jurisditionally segmented (for instane, U.S. versus Canadian segments). If all U.S. projets were ompleted, overall daily deliverability on the national network would inrease by almost 30 billion ubi feet (3 gathering system projets in the Gulf of Mexio and 11 Canadian projets, some of whih are ounted in the U.S. projets, are not inluded). Of all phases/projets, 62 are proposed for ompletion in 1998, 38 in 1999, and 20 in Thirty-nine of the projets all for development of new pipeline systems or failities at new international border points (Table B2). 120 Without firm ustomer ommitments, neither the neessary regulatory 121, Natural Gas Pipeline and System approval nor any needed external finaning will be forthoming. Nevertheless, Expansions, Natural Gas Monthly, DOE/EIA-0130(97/04) Washington, DC, it is possible that some ustomers might bak out of these ommitments after April 1997). initial regulatory approval, thereby leaving the final implementation of a 122, Natural Gas Pipeline and System projet in doubt. Expansions, Natural Gas Monthly (April 1997), Table SR2. 119

125 Figure B1. General Loation of Major Natural Gas Pipeline Constrution Projets Completed in 1997 (Keyed to Table B1) BC AB SK 7 MB 1 5 Canada WA OR Western 44 CA NV ID Central UT AZ MT ND TX 16 MN ME WI MI 2 SD ON VT 9 Midwest WY 6 NH 4 3 NY 24 MA IA 13 NE 14 PA OH IL IN 25 RI CO 21 CT KS MO DE NJ KY VA Northeast 43 DC MD TN 22 OK NC AR NM SC 46 Southwest LA MS AL GA 30 QU Southeast NK Mexio FL MX Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline Constrution Database, as of Marh Reent Developments and Proposals The least amount of interstate pipeline development in 1997 ourred in the Western Region with the ompletion of only one small projet (13 MMf/d) serving the Reno area of 123 Nevada and California. In addition, the Western Region has the least amount of proposed new pipeline apaity development of the regions. This is not surprising sine the region urrently has an exess of interstate apaity. Between 1990 and the end of 1996, interstate apaity into the region inreased by 45 perent, from 7.1 to 10.3 Bf/d, more than for any other region (see Chapter 4). One other projet was ompleted within the Western Region in 1997, 123 the El Paso Havasu Crossover expansion. However, the purpose of this expansion was to inrease the apability of the El Paso system to deliver additional supplies to West Texas, not for servie within the Western Region itself. Other regions of North Ameria saw more extensive pipeline development in 1997 or are slated for signifiant expansions in the next several years. These expansions an be looked at in two ways. First are those projets that are designed to improve aess to developing prodution areas whih have beome apaity onstrained. On the opposite side of the oin are the pipeline expansions that are designed to improve transportation to expanding market areas and whih may or may not be tied in with aessing developing prodution soures. The following setions look first at projets and trends that are prodution-area foused and then at those that are geared toward speifi markets. Prodution Areas Gulf of Mexio One of the more signifiant events of the past several years has been the inreased attention to development of gas 120

126 Table B1. Major Natural Gas Pipeline Constrution Projets Completed in 1997, by Terminating Region Ends FERC In New Cost Added in Begins in Map Doket Servie or Estimate Capaity Year State State Region Key Pipeline/Projet Name Number Date Expansion Miles (million $) (MMf/d) Canada 1997 QU SK Canada 1 TransCanada System Expn Expn 128 NA NY QU Canada 2 TransCanada Import (Iroquois NY) Expn NA NA NY QU Canada 3 TransCanada Import (Chippawa NY) Expn NA NA NY QU Canada 4 TransCanada Import (Niagara NY) Expn NA NA MN SK Canada 5 TransCanada Import (Noyes MN) Expn NA NA 56 Central 1997 WY WY Central 6 CIG Wind River Lateral Expn CP Expn NA ND SK Canada 7 ISP Solution Gas Imports CP New MO WY Central 8 KN Interstate Pony Express CP New WY WY Central 9 MIGC HiLight Plant Expn CP Expn NA NE CO Central 10 Trailblazer Eastward Expn CP Expn 445 NA KS WY Central 11 Williams Gas WY-KS Expn CP Expn NA MO KS Central 12 Williams Gas KS-MO Expn CP Expn CO WY Central 13 Wyoming Interstate Eastward CP Expn NA Midwest 1997 MI IL Midwest 14 ANR Mihigan Leg Expn CP Expn WI KS Central 15 Northern Natural Peak Day 2000 I CP Expn WI MB Canada 16 Viking System-Wide Expn CP Expn Northeast 1997 CT CT Northeast 17 Algonquin Eletri Load Lateral CP Expn PA WV Northeast 18 CNG Seasonal Servie Expn CP Expn NA VA PA Northeast 19 CNG PL-1 Phase I CP Expn NA VA VA Northeast 20 Columbia/Commonwealth PL Expn NA Expn NA NA VA PA Northeast 21 Columbia Gas Market Expn I CP Expn VA TN Southeast 22 East Tennessee System Wide CP Expn MD DE Northeast 23 Eastern Shore Bridgeville Expn CP Expn PA NY Northeast 24 National Fuel Niagara Expn CP Expn PA PA Northeast 25 Texas Eastern Virginia Natural Expn CP Expn NA NA PA PA Northeast 26 Texas Eastern Columbia Expn CP Expn PA PA Northeast 27 Texas Eastern Line 1-A Expn CP Expn PA PA Northeast 28 Transo Poono Projet CP Expn Southeast 1997 AL AL Southeast 29 MidCoast Pipeline System Expn CP Expn NA SC GA Southeast 30 SONAT Zone 3 GA-SC-TN CP Expn SC SC Southeast 31 South Carolina Pipeline Expn Expn NA NC NC Southeast 32 Transo Maiden Lateral Expn CP Expn SC MS Southeast 33 Transo Sunbelt Projet NA Expn Southwest 1997 GM GM Offshore 34 DIGS Main Pass Gathering CP New TX TX Southwest 35 Delhi Pipeline South Texas Expn Expn 53 NA LA GM Offshore 36 Disovery Pipeline CP New TX AZ Western 37 El Paso Havasu Crossover CP Expn GM GM Offshore 38 Garden Banks Offshore System CP New 50 NA LA GM Offshore 39 Koh Bastian Bay CP Expn 16 NA GM GM Offshore 40 Manta Ray Gathering System CP New LA GM Offshore 41 Nautilus System CP New OK OK Southwest 42 Transok West-to-East System Expn Expn NM NM Southwest 43 Transwestern Bloomfield Expn CP Expn -- NA 25 Western 1997 CA NV Western 44 Paiute Pipeline North Taho Lateral CP New Mexio 1997 MX CA Western 45 SoCal Calexio/Mexiali Export NA New 1 a MX TX Southwest 46 El Paso Samalayua II CP New Less than $1 million. All ost estimates are in U.S. dollars. a MMf/d = Million ubi feet per day. Expn = Expansion. NA = Not available. -- = Not appliable. CIG = Colorado Interstate Gas Co.; CNG = CNG Transmission Co; DIGS = Dauphin Island Gathering System; GM = Gulf of Mexio; NGPL = Natural Gas Pipeline Co. of Ameria; NSPC = Northern States Power Co.; SoCal = Southern California Gas Co.; SONAT = Southern Natural Gas Co.; Tenneo = Tennessee Gas Pipeline Co.; TCPL = TransCanada Pipeline Ltd.; Transo = Transontinental Gas Pipeline Co. Note: Bold underlined items indiate projet rosses regional boundary. Soure:, EIAGIS-NG Geographi Information System, Natural Gas Proposed Pipeline Constrution Database, as of Marh 1998, ompiled from Federal Energy Regulatory Commission filings and various industry news soures. 121

127 Figure B2. General Loation of Major Proposed Natural Gas Pipeline Constrution Projets, (Keyed to Table B2) BC A10 A5 AB A1 A2 A9 SK A7 A6 B13 A3 MB Canada WA G1 OR Western CA G3 G2 ID G5 G6 NV G4 H5 Central MT B14 WY B5 B9 B11 B3 B2 G7 B8 UT B10 CO F11 F3 F12 AZ NM H3 Mexio ND B1 C16 C2 C11 C17 NK QU ME C1 B7 C12 WI A4 MN C6 D10 D18 C20 MI SD ON D7 C18 Midwest A8 VT D25 NH D6 B6 C15 D19 D5 NY C8 A11 D26 D23 C13 C9 MA IA C19 D13 D4 NE D8 C3 C4 D27 C5 C10 OH D17 PA D20 C7 IL D14 D9 D16 RI D15 D24 D21 D3 CT B4 KS MO B12 IN WV D1 D12 DE NJ C14 D22 KY D11D28 VA Northeast TN E6 D2 E14 E11 DC MD OK E9 AR E15 NC E10 E12 E7 SC E13 F9 F6 E5 TX E4 MS LA AL GA Southeast F4 F15 F16 E8 F1 F7 E3 E2 F13 F10 E1 FL F2 F8 H4 F14 F5 H1 H2 Southwest Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline Constrution Database, as of Marh resoures in the Gulf of Mexio and, speifially, in the being developed there most notably in the Ship Shoal, deeper waters (greater than 200 meters) of offshore Louisiana, Green Canyon, Destin Corridor, Garden Banks, and Alabama, and Mississippi. In 1997, six natural gas pipeline 124 Mississippi Canyon areas. Companies suh as Shell Oil, projets were ompleted in the Gulf, representing a total of Transontinental Pipeline, and Williams Natural Gas 3.2 Bf/d of new pipeline apaity (Table B1). Three of these Transmission are involved (Table B2). Development of projets now bring an additional 2.1 Bf/d to onshore offshore and deep water pipeline-related projets represents Louisiana, while the other three (1.1 Bf/d) operate as 52 perent of the 3.7 Bf/d of planned additions in the gathering systems linking produing platforms in the Gulf Southwest Region and 44 perent of the 4.0 Bf/d in the with mainlines direted to onshore failities. The largest of Southeast Region. the new systems inlude the Nautilus and Texao Disovery pipelines, both with apaities of 0.6 Bf/d. The remaining proposed onshore expansion projets in the Southwest Region are designed primarily to inrease aess At least 10 offshore projets, representing more than to supplies in the east and south Texas and in the San Juan 3.7 Bf/d of apaity, have been proposed for development in Basin of New Mexio. Several proposed projets in south 1998/1999. Most of these projets would reah into the deep Texas are designed to support exports to Mexio, if and when water area of the Gulf to tap several new prodution soures the onneting export failities are finally put in plae. Three projets would diret supply to the Southeast (Alabama and 124 Mississippi) and three to the Southwest (Louisiana). The other projets would be gathering systems. 122

128 Table B2. Major Proposed Natural Gas Pipeline Constrution Projets, by Terminating Region and Planned In-Servie Year, Ends FERC Status New Cost Added in Begins in Map Doket As of or Estimate Capaity Year State State Region Key Pipeline/Projet Name Number a Expansion Miles (million $) (MMf/d) Canada 1998 SK AB Canada A1 Alberta Energy/TransCanada Expn -- Approved Expn SK SK Canada A2 Foothills Pipeline Eastern Expn -- Approved New QU SK Canada A3 TransCanada 1998 System Expn -- Pending Expn NB NS Canada A4 Maritimes & Northeast Phase II -- Pending New AB AB Canada A5 NOVA System Expn -- Pending Expn 125 1,070 2, QU SK Canada A6 TransCanada System 1999 Expn -- Pending Expn NA NA NA 1999 MB AB Canada A7 TransCanada Voyageur Link -- Announed Expn NA NA 1, ON MI Midwest A8 Vetor Pipeline (Canada Portion) -- Pending New , SK BC Canada A9 Alliane Pipeline (Canada Portion) -- Pending New , BC BC Canada A10 ANG Kootenay Paifi Pipeline -- Pending New ON MI Midwest A11 TriStatePipeline (Canada Portion) -- Announed Expn NA NA 300 Total New Capaity 8,637 Central 1998 CO CO Central B1 CIG Campo Lateral CP Approved Expn CO CO Central B2 PSCO Front Range -- Pending Expn WY CO Central B3 KN Interstate Front Runner CP Pending New 109 NA NE OK Southwest B4 NGPL Amarillo Upgrade CP Approved Expn WY WY Central B5 MIGC Southern Mainline Expn CP Pending Expn NA IA IA Central B6 Northern Border Harper Expn CP Approved Expn 142 NA IA SK Canada B7 Northern Border Monhy Expn CP Approved Expn WY UT Central B8 Questar Utah Mainline Expn CP98-66 Approved Expn NA UT WY Central B9 Questar Mainline (Line 58) Expn CP Approved Expn CO CO Central B10 TransColorado Pipeline (Northern) CP Approved New WY WY Central B11 WIG Larimie Compressor Expn CP Pending Expn NA MO MO Central B12 Williams Natural Gas St Louis Expn -- Announed Expn 200 NA ND SK Canada B13 Alliane Pipeline (Import Station) CP Approved New , WY SK Canada B14 Altamont Pipeline CP Approved New Total New Capaity 5,143 Midwest 1998 MI MI Midwest C1 Great Lakes Seurity Looping II CP Approved Expn MI MB Canada C2 Great Lakes System Wide Expn CP Approved Expn IL IA Central C3 NGPL Amarillo Expn CP96-27 Approved Expn IL IA Central C4 Northern Border Manhattan Extn CP Approved New 200 NA WI KS Central C5 Northern Natural Peak Day 2000 II CP97-25 Approved Expn 5 NA MN MN Midwest C6 Northern Natural Line D Expn CP Approved Expn OH IN Midwest C7 Texas Eastern Spetrum Expn CP On hold Expn WI IL Midwest C8 ANR IL-WI Expn CP Approved Expn OH IL Midwest C9 ANR Independene Tie-in Expn CP Pending Expn 30 NA IN IL Midwest C10 Crossroads/CNG -- Announed Expn 20 NA MN MN Midwest C11 Great Lakes Carlton Projet CP98-96 Pending Expn MI MI Midwest C12 Great Lakes Sault Looping CP Pending Expn IL IA Central C13 Northern Natural Gas East Leg Announed Expn OH TN Southeast C14 Tenneo Eastern Express -- Announed Expn NA MI IL Midwest C15 Vetor Pipeline (US Portion) -- Pending New , IL SK Canada C16 Alliane Projet (US Portion) CP Pending New , MI MB Canada C17 Great Lakes 300 Expn CP Pending Expn IN SK Canada C16 Northern Border Projet Announed Expn NA NA MI IL Midwest C19 TriState Pipeline Projet -- Announed New 275 NA IL MB Canada C20 Viking Voyageur Projet NA Pending New 773 1,240 1,400 Total New Capaity 8,234 Northeast 1998 VA PA Northeast D1 Columbia Gas Market Expn II CP Pending Expn VA VA Northeast D2 East Tenn Roanoke Expn CP98-40 Pending Expn 60 NA MD DE Northeast D3 Eastern Shore System Expn NA Pending Expn 98 NA NY QU Canada D4 Iroquois Import Expn CP Pending Expn PA NY Northeast D5 National Fuel Niagara/Leidy I CP98-94 Approved Expn ME MA Northeast D6 Portland/Maritimes & Northeast I CP Approved New ME QU Canada D7 Portland Pipeline Projet CP Approved New MA MA Northeast D8 Tenneo/DOMAC CP Pending New PA PA Northeast D9 Texas Eastern Virginia Natural Expn CP Pending Expn NA NA VT QU Canada D10 Vermont Gas System Import Expn CP Approved Expn 190 NA VA VA Northeast D11 VNG Saltville P-25 Line -- Approved Expn VA PA Northeast D12 CNG PL-1 Phase II CP On Hold Expn NA NA NY ON Canada D13 Columbia s Millennium PL CP Pending New PA WV Northeast D14 CNG SSE Expn CP On Hold Expn PA OH Midwest D15 CNG Market Value Projet NA Announed Expn NA NA VA PA Northeast D16 CNG MAS (Market Area Storage) CP Pending Expn NA NA VA PA Northeast D1 Columbia Gas Market Expn III CP Pending Expn PA OH Midwest D17 Independene Pipeline CP Pending New , ME NB Canada D18 Maritimes & Northeast II (US Portion) CP Approved New ME QU Canada D7 Portland Pipeline 1999 Expn -- Announed Expn NA NA PA PA Northeast D9 Texas Eastern Virginia Natural Expn CP Pending Expn NA NA NY PA Northeast D20 Transo MarketLink Expn -- Announed Expn NY NJ Northeast D21 Duke Energy Crossbay Projet -- Announed New 44 NA VA VA Northeast D22 VNG Saltville P-24 Line -- Pending Expn 40 NA

129 Table B2. Major Proposed Natural Gas Pipeline Constrution Projets, by Terminating Region and Planned In-Servie Year, (Continued) Ends FERC Status New Cost Added in Begins in Map Doket As of or Estimate Capaity Year State State Region Key Pipeline/Projet Name Number a Expansion Miles (million $) (MMf/d) 2000 MA NH Northeast D23 Algonquin HubLine Projet -- Announed New 70 NA NY IL Midwest D24 Duke Energy Spetrum PL -- Announed Expn NF NH Canada D19 MarineLine Subsea Projet CP98-30 On hold New 1,570 3, NY QU Canada D25 Iroquois NY City Expn -- Announed Expn 27 NA PA ON Canada D26 Tenneo Niagara-Leidy Expn -- Announed Expn NA NA MA TN Southeast D27 Tenneo Eastern Express Announed Expn NA PA PA Northeast D9 Texas Eastern Virginia Natural Expn CP Pending Expn NA NA VA VA Northeast D28 VNG Tidewater Intrastate PL -- Announed New 350 NA 315 Total New Capaity 8,324 Southeast 1998 AL GM Offshore E1 DIGS (Dauphin Island) Phase II CP98-6 Approved Expn MS GM Offshore E2 Destin Corridor Offshore CP Approved New , GM GM Offshore E3 Destin Main Pass Laterals CP Pending Expn GA AL Southeast E4 SONAT Zone 2 & 3 Expn CP Approved Expn NA AL AL Southeast E5 SONAT Dallas County Expn CP Approved Expn TN TN Southeast E6 Tengaso East Tennessee PL Link -- Approved New GA AL Southeast E7 Transo Cherokee Projet CP Approved Expn MS GM Offshore E8 Transo Mobile Bay Expn CP97-92 Approved Expn AL TN Southeast E9 U.S. Gypsum Lateral CP Approved New KY LA Southwest E10 Columbia Gulf Mainline Expn -- Announed Expn 820 NA NC NC Southeast E11 Cardinal Pipeline (Transo) -- Approved Expn GA AL Southeast E12 SONAT/East Tenn Connetion CP Approved Expn TN LA Southwest E13 Tenneo Express 500 Expn NA Announed Expn NA NA NC NC Southeast E14 Transo Pine Needle LNG Link CP Approved New TN GA Southeast E15 Cumberland Pipeline (Transo) -- Pending Expn NA NA 200 Total New Capaity 3,221 Southwest 1998 LA GM Offshore F1 ANR Conh Projet CP97-71 Approved Expn TX TX Southwest F2 Coastal States Roma Export Line -- Approved New NM NM Southwest F3 El Paso San Juan Expn -- Pending Expn LA LA Southwest F4 Mid-Louisiana Baton-Rouge Expn -- Announed Expn 25 NA TX TX Southwest F5 MidCon Texas Pipeline CP Approved New LA LA Southwest F6 Noram Gas Trans Line-F Expn CP Approved Expn LA GM Offshore F7 Shell Mississippi Canyon Expn NA Announed Expn NA NA LA LA Offshore F8 Tenneo South Pass 77 Expn CP Pending Expn LA LA Southwest F9 Texas Gas PL Hougton Expn CP Approved Expn NA GM GM Offshore F10 Transo Sealeg Projet CP Approved Expn NM CO Central F11 Transwestern San Juan Expn I CP Approved Expn NM NM Southwest F12 Transwestern San Juan Expn II CP Approved Expn LA GM Offshore F13 Trunkline Terrebone Expn CP Approved Expn GM GM Offshore F14 Williams Natural Gas Genesis Expn -- Pending New 35 NA LA TX Southwest F15 ANR Katy Projet -- On hold New LA GM Offshore F16 Transo Crossover Projet -- Announed New/Expn 170 NA 264 Total New Capaity 3,715 Western 1998 WA OR Western G1 Northwest PL Columbia River Extn -- Announed Expn NA WA BC Canada G2 PGT Mainline Expn -- Announed Expn CA CA Western G3 Paifi Offshore Santa Barbara Expn -- Approved Expn NA NA CA CA Western G4 San Diego G&E Pipeline 2000 CP Approved New NV ID Western G5 NWPL Silver Gem Lateral -- Announed New NV NV Western G6 Pauite Silver Gem/Elko Expn -- Announed Expn 43 NA NV UT Central G7 CIG Utah-Nevada Line -- Announed New 360 NA 250 Total New Capaity 584 Mexio 1998 MX TX Southwest H1 Coastal States Roma Export Point CP Approved New 1 NA MX TX Southwest H2 MidCon Texas Roma Export Point CP Approved Expn 1 NA MX NM Southwest H3 PNM Gas Servies Export CP93-98 Approved New NA NA MX TX Southwest H4 Houston Pipeline Export CP On hold New 22 NA MX CA Western H5 SoCal Projet Veinos CP Approved New Total New Capaity 1,375 a Announed = Prior to filing with regulatory authorities. Pending = Before regulatory authority for review and aeptane. Approved = Fully or onditionally approved by regulating authority; may or may not be under onstrution. On Hold = May be aneled or postponed due to hanged market or regulatory onditions. b Cost and added apaity are the same for this and previous line item. MMf/d = Million ubi feet per day. Expn = Expansion. NA = Not available. -- = Not appliable. Extn = Extension. CIG = Colorado Interstate Gas Co.; CNG = CNG Transmission Co; DIGS = Dauphin Island Gathering System; GM = Gulf of Mexio; NGPL = Natural Gas Pipeline Co. of Ameria; NSPC = Northern States Power Co.; NWPL = Northwest Pipeline Co.; PSCO = Publi Servie Co. of Colorado; SoCal = Southern California Gas Co.; SONAT = Southern Natural Gas Co.; Tenneo = Tennessee Gas Pipeline Co.; TCPL = TransCanada Pipeline Ltd.; Transo = Transontinental Gas Pipeline Co.; VNG = Virginia Natural Gas Co. Notes: All ost estimates are in U.S. dollars. Bold underlined items indiate projet rosses regional boundary. Soure:, EIAGIS-NG Geographi Information System, Natural Gas Proposed Pipeline Constrution Database, as of Marh 1998, ompiled from Federal Energy Regulatory Commission filings and various industry news soures. 124

130 San Juan Basin (New Mexio) Aess Until reently, the apaity available to move gas from the San Juan Basin area eastward was limited. The rapid development of the area s oalbed methane and other supplies in the area during the late 1980's led to an exess in produtive apaity. Originally the new prodution was expeted to be onsumed in the California market, and pipeline apaity was developed with that in mind. Today, however, the emphasis is on finding ways to expand deliverability for produers in the basin and move some of this supply eastward to link with market enters in the Texas Panhandle as well as those loated in the Waha area of southwestern Texas. From there the gas ould be redireted through northern and eastern Texas to Midwest and Northeast markets. The two major interstate pipeline ompanies in the area, Transwestern Pipeline Company and El Paso Natural Gas Company, have undertaken efforts to expand and enhane failities on their respetive systems, whih would allow them to diret more prodution eastward to the Waha/Permian Basin enters. Although no pipeline projets have been proposed for the area, the Cotton Valley Trend of East Texas is expeted to beome a major new soure of gas prodution over the next several years. The same is true of the area around Southeast Texas. In 1997, Delhi Pipeline Company and several other intrastate pipelines expanded parts of their gathering and mainline systems to aommodate urrent and future new prodution. The question remains, however, whether urrent interstate apaity levels, whih are not fully utilized at the present, an handle the new prodution without expansion. The proposed ANR Katy projet, whih was, in part, targeted at shippers who potentially might want to aess this new prodution, did not generate as muh interest as the ompany expeted when an open-season was offered in mid The future of the projet is urrently under review by the ompany. Roky Mountain Area Aess In the past, Roky Mountain supplies (Colorado, Wyoming and Utah) generally moved to a strong southern California gas market, but the urrent emphasis of area produers is to inrease their presene in loal energy markets and to extend their ustomer base further in U.S. Midwestern and Eastern In 1997, both pipeline ompanies ompleted projets that markets. Customers in the Midwest and East are also very improved deliverability out of the San Juan Basin and planned interested in having greater aess to these relatively lower several additional projets that would relieve the ongoing pried supplies. apaity onstraint issue in the area. For instane, Transwestern Pipeline Company added an additional In 1997, several natural gas pipeline projets were ompleted 25 MMf/d with the expansion of ompression on its system that furthered that goal. For instane, KN Interstate Pipeline within the basin (Table B1). It also has Federal Energy Company plaed its Pony Express line (0.26 Bf/d) in Regulatory Commission (FERC) approval to expand its loal servie in August and the Trailblazer/Overthrust/Wyoming apabilities by 245 MMf/d in El Paso Natural Gas Interstate system (0.1 to 0.2 Bf/d) expansion was ompleted Company also plans to expand its loal San Juan Basin in the last quarter of the year. The latter expansion inreased apabilities by 116 MMf/d in 1998 (pending FERC approval) the system s deliverability to its interonnetion with the in response to rising prodution demands. Natural Gas Pipeline Company of Ameria s Amarillo line, whih transports supplies to the Midwest Region. In addition, with the ompletion of the full TransColorado Pipeline system (from northern Colorado to northern New The proposed pipeline expansion projets in the area, for the Mexio) in 1998, a portion of its 0.3 Bf/d apaity ould be most part, target expanding regional servie as an outlet for available to loal produers/shippers on an as-available basis. expanding area prodution. Two major projet proposals, the KN Interstate Pipeline Company s Front Runner projets The El Paso Natural Gas Company s ompleted its Havasu (Table B2), both intend to transport Wyoming supplies to a Crossover expansion projet in mid This projet uses growing Denver, Colorado, marketplae. The Questar expanded apaity on the westward-bound portion of the Pipeline Company proposes to expand its apabilities in the system to move supplies that are redireted eastward (either Salt Lake City area. physially or by displaement) just east of the California border. The expansion upgraded the Havasu Crossover, whih In addition to the expanding prodution in areas of the Roky links the north and south parts of the El Paso system. These Mountains loated in Wyoming, Utah, and northern Colorado, system enhanements inreased El Paso deliverability in the the Powder River area of southern Montana and northern Waha area of West Texas by an additional 180 MMf/d. Wyoming is expeted to develop into a major produing area over the next deade. Already several of the pipeline projets Potential East and South Texas Expansions disussed earlier have antiipated aess to this area s prodution in their design. 125

131 Improved Aess to Canadian Supply During 1997, the TransCanada Pipeline system inreased its domesti deliverability by 119 MMf/d and expanded several of its export points to the United States. However, only one of the interonneting U.S. pipelines (Viking Gas Transmission Company) expanded its apaity aordingly. The TransCanada export upgrades were primarily to alleviate some of its own limitations. Most of the U.S. pipelines were already apable of aepting the inreased flows. The ompletion of these projets in 1997 only partially relieved the existing apaity onstraint problem on the TransCanada system. Flow restritions on the system have limited western Alberta (Canada) natural gas produers aess to markets to the east during the past several years. However, within Canada, a number of projets are planned that will improve operational flows signifiantly and add to export apability. Although it is doubtful that all will be built, 11 projets within Canada, representing more than 8.6 Bf/d 125 of new apaity, have been proposed for development by the end of Several, like the NOVA system expansion and the new ANG Kootenay Paifi Pipeline, would inrease prodution area exit apaity. However, the bulk of the new apaity that is being proposed would be longhaul system apaity targeted for eastern Canadian natural gas markets (whih are growing rapidly) and to expand export apabilities (Figure B3). Refleting the growing Canadian prodution and desire to flow more of that gas to U.S. markets, 14 projets have been proposed that ould add as muh as 5.9 Bf/d to U.S. import apaity from Canada during the next 3 years, an inrease of perent from the 1997 level. The volume inrease is 17 perent more than the total Canadian import apaity added from 1991 through 1997, 5.0 Bf/d (see Chapter 3). This antiipated growth also reflets the ontinuing U.S. demand for Canadian natural gas, espeially in the Midwest and Northeast regions. These efforts inlude several very large projets. For example, a new natural gas pipeline (the Alliane projet) would bring gas from British Columbia to the Chiago, Illinois, area along the right-of-way of an existing oil pipeline. Several other projets are ompeting with the Alliane projet, inluding 125 Final apaity levels for TransCanada Pipeline Company s 1999 expansion effort were not available as of Marh Does not inlude two projets, representing 1.1 Bf/d apaity, whose hanes of suess are marginal. It also does not inlude the Columbia Millennium projet into the Northeast Region whose apaity is tied in with the import apaity into the Midwest and the 1.6 Bf/d Alliane Pipeline import station, whih for the most part is aounted for in that projet. the Viking Voyageur Pipeline, whih is a 1.4 Bf/d line between the Noyes, Minnesota, import point and the Chiago, Illinois, area, and the Northern Border Projet 2000, whih is 127 a 400 MMf/d expansion that inludes a proposal to extend the system to Indiana and possibly to the Mihigan-Canada border to serve the Ontario marketplae. (Note: In late April 1998 the sponsors of the Viking Voyageur Projet announed that it was unlikely that they would be able to seure enough future shipper ommitments and available prodution in Canada to make the projet viable at its proposed level. As a result, the projet may terminate or downsize. Sine its 1999/2000 expansion plans are prediated in part upon the Viking Projet, TransCanada Pipeline s expansion plans may have to ut bak as well.) In addition, Great Lakes Gas Transmission in the Midwest Region and Iroquois Transmission in the Northeast plan to expand their existing systems by 441 and 160 MMf/d, respetively, during the next several years. Beause of the growing demand for Western Canadian supplies in Eastern Canada and the United States, TransCanada Pipeline Ltd. applied to the Canadian National Energy Board in early 1998 to extend its expansion plans to aommodate an interonnetion with the Viking Voyageur projet and larger potential demand in the Canadian domesti market. The new apaity would be phased in over 2 years beginning in Currently, TransCanada is in the proess of revising its expansion plans for 1999 to reflet its ommitments to the Voyageur expansion. In August 1996, the Federal Energy Regulatory Commission approved onstrution of the Northern Border Pipeline Company expansion projet, whih would add 0.7 Bf/d to import apaity at the Montana border. Correspondingly, Foothills Pipe Line Ltd. of Canada, whih interonnets with Northern Border Pipeline at Monhy, Montana, would expand its eastern leg by the same amount. On the Canadian east oast, several new pipelines have been proposed to move gas supplies being developed off the Canadian Atlanti oast near Sable Island to markets in Canada and the United States (Table B2). The Maritimes & Northeast pipeline projet would move Sable Island supplies to the Northeastern United States. The Maritimes & Northeast pipeline projet s route will take it diretly into the State of Maine and through New Hampshire to interonnetions with the Tennessee Gas Pipeline system in Massahusetts. Another projet, the MarineLine Subsea pipeline has been proposed. 128 It would not only provide an alternative transportation route 127 Original plans were for a 1.3 Bf/d expansion, but the projet s size has been ut beause of less-than-expeted market interest. 128 In Marh 1998, this projet was plaed in an inative status, pending ompletion of additional geologial and geophysial surveys. 126

132 Figure B3. Planned Projets Related to Imports of Canadian Gas, Nova & ANG Paifi (Expansion) PG&E Transmission-NW (Expansion) Altamont Pipeline (New) Foothill Pipeline Co (Expansion) Northern Border Pipeline Co (Expansion) (New Setion) Natural Gas PL of Ameria (Expansion) TriState Pipeline (New) TransCanada Pipeline LTD (Expansion) Alliane Projet (New) Viking Voyageur (New) Great Lakes Transmission Co (Expansion) Viking Transmission Co (Expansion) Vetor Pipeline (New) Phase I Iroquois Pipeline Co (Expansion) Portland Pipeline (New) Phase II MarineLine Subsea (New) Maritimes & Northeast (New) PanEnergy's Spetrum (Expansion) Tenneo Eastern Express (Expansion) Columbia's Millennium (Expansion) Independene Pipeline (New) = Expansion Diretion Soure: (EIA), EIAGIS-NG Geographi Information System, Natural Gas Pipeline Constrution Database, as of Marh from Sable Island but also would handle reeipts (supplies) from as far north as Newfoundland, through a sea route passing through the Sable Island fields and southward to landfall in New Hampshire. Market Areas Midwest In 1997, only three interstate pipeline projets were ompleted in the Midwest Region (Table B1), adding 441 MMf/d of new apaity. These projets represented an inrease to intraregional apaity of only about one-half of 1 perent. However, one projet (ANR Mihigan Leg expansion) resolves a apaity bottlenek in the region, while the other two expanded deliverability to growing markets in Wisonsin and viinity. Based upon urrent proposals, natural gas pipeline deliverability to the Midwest Region will grow substantially by the end of 2000, with 8.2 Bf/d of new interstate apaity planned overall, the seond highest of the six regions. But what really distinguishes the growth in the Midwest is that the vast majority of new apaity would be on newly built trunklines or extensions to existing pipelines bringing supplies from Canada. Ten of these projets would inrease interregional deliverability by a total of 5.3 Bf/d. The Midwest will be the terminus for the Alliane projet, whih alone would inrease area servie by 1.3 Bf/d. Exluding the extension of Canadian supplies via the Northern Border Pipeline to Manhattan, Illinois (near Chiago), and Natural Gas Pipeline Company of Ameria s (NGPL) Amarillo expansion (110 MMf/d) destined for the same area, the Midwest Region s aess to Canadian supplies ould inrease by as muh as 117 perent (3.6 Bf/d) from the 1997 level (3.0 Bf/d). Two new pipelines, TriState (0.5 Bf/d) and Vetor (1.0 Bf/d), have been proposed to tranship supplies arriving via Voyageur, Alliane, and Northern Border pipelines in the Chiago area to markets in eastern Mihigan and southern 127

133 Ontario, Canada. The Vetor pipeline would provide an integral link in support of Columbia Gas Transmission Company s Millennium projet, whih has been proposed to begin gas deliveries in the fall of 1999 to ustomers in the Northeast (see next setion). Vetor would tranship supplies through Canada via the Union Gas System (Ontario) from the St. Clair export point and Dawn (Ontario) storage to the Millennium pipeline at Niagara, New York. Northeast More pipeline expansion projets were ompleted in the Northeast Region in 1997 than in any other part of North Ameria. Twelve projets, aounting for about 770 MMf/d of additional deliverability, or 2 perent of intraregional pipeline apabilities, were plaed in servie. However, only one of these projets (24 MMf/d) inreased interregional deliverability (Table B1). The apaity inrease within the region was exeeded only in the Southwest Region. Almost all of the projets were to improve deliverability within loal markets or to address bottleneks that were limiting servie in areas of growing demand. Texas Eastern Transmission s several expansion projets were implemented primarily to resolve the latter problem. The Northeast has the most natural gas pipeline projets (28) slated for development and they represent the largest amount of proposed new pipeline apaity within any region of the United States, 8.3 Bf/d. Several of the projets are ontinuations of ones that began in 1996 or 1997 and are being phased in over several years. While many of the proposed projets are smaller regional expansions serving loal market areas, more than 59 perent of the added apaity would be on pipeline systems delivering from outside the Northeast Region. Of the 5.0 Bf/d of proposed new interregional apaity, more than 53 perent would arry supplies originating in Canada. Many of these projets have been planned beause of expetations that an exess deliverability situation ould our in the Chiago area if all the projets slated to bring Canadian supplies into the Midwest are ompleted. This possibility has spurred several ompanies to plan large-sale projets that would extend some of this new apaity further eastward to Northeast markets. For example, ANR Pipeline Company and Transontinental Gas Pipeline Company have proposed the jointly owned Independene projet, whih ould arry 1.0 Bf/d from ANR s line in northwestern Ohio to a major interonnetion with Transontinental s line in Leidy, Pennsylvania, a major hub serving the Northeastern marketplae. The new line would also be attrative to Canadian-gas shippers seeking an alternative route to Northeast markets. It ould also provide an alternative route and opportunity for shippers now moving gas from the Southwest to the Midwest to reah ustomers in the Northeast. Other projets that would move some of the new Midwestern pipeline supplies eastward inlude Tennessee Gas Pipeline Company s proposed Eastern Express projet and Duke Energy Corporation s Spetrum projet. These two projets alone represent a total of 1.2 Bf/d of new apaity into the Northeast. Inluding the Independene and Millennium projets, as well as other import projets slated for development during the next several years, new apaity into the region ould reah 5.2 Bf/d, adding signifiantly to the 12.4 Bf/d existing at the lose of The Spetrum projet (0.5 Bf/d) would extend from the Chiago, Illinois, area to New York and New England, mostly using expanded failities along Duke Energy s affiliated pipelines: Panhandle Eastern, Texas Eastern, and Algonquin Gas Transmission systems (west to east). In addition, an interonnetion with another affiliate, Trunkline Gas Company, ould be utilized to move gas supplies from the Southwest Region if appropriate (as ould the Panhandle Eastern Pipeline system). The Eastern Express projet (0.7 Bf/d) would utilize Midwestern Gas Transmission Company (an affiliate of Tennessee Gas Pipeline Company) to ship supplies southward (or though displaement) to Tennessee Gas s interonnetion in northern Tennessee and then, through expanded failities on its existing system, transport supplies from the Midwest to the east oast. In addition, the Eastern Express projet would inlude expansion (0.2 Bf/d) of Tennessee Gas s pipeline between its Niagara, New York, import point and its interonnetions near Leidy, Pennsylvania, and its northern line extending diretly to New England. Canadian import expansions slated for development in 1998 and 1999 will result in inreased apaity at several import points into the Northeastern United States and development of at least one new import point (for Columbia Gas Transmission s Millennium projet). For example, in response to TransCanada s multiyear expansion plans, Iroquois Pipeline Company has proposed to expand its system by about 195 MMf/d, phased in during 1998 and Also supported by the TransCanada expansion will be the new Portland Natural Gas Pipeline (178 MMf/d), whih would replae and expand Granite State Pipeline Company s leased line (31 MMf/d) that urrently brings Canadian gas to Maine via Vermont and New Hampshire. Combined with the Millennium import level of 0.7 Bf/d and several import expansions related to other projets, diret Canadian export apaity to the U.S. Northeast ould inrease by about 2.6 Bf/d by the end of 2000, a 91-perent inrease over the 1997 level. 128

134 Planned expansions in the Northeast Region are also of proposed apaity additions, all of whih are sheduled to somewhat unique in that several projets represent be in servie sometime in ooperative efforts among regional pipeline systems. For example, the Texas Eastern expansion of servie to some of Five of these projets (1.2 Bf/d of expansion apaity) its Virginia and eastern Pennsylvania servie areas depends represent an inreased ommitment by Transontinental Gas partly upon the ompletion of the CNG Transmission PL-1 Pipeline Company to ustomers within the region. Four other line and Seasonal Servie expansion projets, inluding projets also represent greater servie to regional markets, improvements to storage deliverability. Columbia Gas espeially in the Atlanta, Georgia, area and the servie Transmission, with its Market Expansion projet, is also territory of Atlanta Gas Light Company. Growth in the planning improvements (espeially to storage servies) on its regional industrial market is helping to spur demand for system that would inrease deliverability to several major additional natural gas supplies. interonnetions with these same pipelines. National Fuel Gas Supply Company, another major regional system, has Also not to be overlooked in the expansion mix are the proposed upgrades to its system based upon the eventual several projets that are designed to transport some of the ompletion of projets by Columbia, CNG, and Texas growing Southwest regional prodution through the Southeast Eastern. In partiular, National Fuel s projet will to markets in the Midwest and Northeast. The Tennessee Gas omplement CNG s planned improvement to its system for Pipeline Company s Express 500 is one suh proposal, with flowing gas between Leidy, Pennsylvania, a major storage up to 0.2 Bf/d additional apaity to be added by 2000, area and hub interonnetion point, and Steuben County, New inreasing the existing apaity of its Line 500 loated within York, and then northward where CNG and National Fuel have the region. Columbia Gulf Transmission Company also will major interonnetions. The first phases of several of these inrease its mainline apaity by more than 0.2 Bf/d. For the projets were ompleted in past several years, Columbia Gulf system has been operating below its original design apaity beause of an aging Of the 28 singular projets planned within the region infrastruture; the problem would be resolved with the representing 8.3 Bf/d of new apaity, a number are either ompletion of this projet. diretly or indiretly linked by mutual servie needs or 129 partnerships. These projets onstitute about 18 perent, or Mexio Market 1.1 Bf/d, of the new apaity additions in the region. Several projets have been proposed to add to the export Southeast apability of U.S. natural gas ompanies loated near the border with Mexio (Table B2), although only two projets Natural gas pipeline expansions ompleted in the Southeast (237 MMf/d) were ompleted in These were the first Region in 1997 (436 MMf/d) were intended mainly to new export points to Mexio installed in 5 years (Table B1). improve Deliverability within the region, primarily in North None of the proposed projets represents enhanements to and South Carolina, Georgia, and Alabama. These expansions import apabilities, urrently at about 350 MMf/d, a figure represent less than 1 perent of the total 1996 regional that has not hanged sine the 1980s. All of the proposed pipeline apaity levels (Table ES1). One system, projets are to support mostly industrial and power generation Transontinental Gas Pipeline Company, was involved in ustomers loated in the border area. three of the five projets ompleted in In addition to inreasing servie from its North Carolina mainline, If ompleted, the urrently proposed projets would represent ompletion of its Sunbelt projet supported the expansion of about 1.4 Bf/d of additional export apaity (Table B2). the South Carolina Pipeline system, whih was also Currently (1997), export apaity to Mexio stands at 1.1 ompleted in Bf/d. Several of the proposed projets are ompeting within and for the same market. For example, Both the MidConnegotiations. Fifteen expansion projets, representing a potential 3.2 Bf/d Texas Pipeline Company (Figure B2) and Coastal States Gas of new apaity development, are proposed for the Southeast Transmission Company are seeking to negotiate with Region. About 54 perent of this apaity is geared toward Mexian buyers for firm shipping agreements to essentially improving regional aess to deep water prodution in the the same general area. Nevertheless, both ompanies view Gulf of Mexio. Offshore projets represent about 1.7 Bf/d their projets as proeeding regardless of the outome of These two ompanies also have plans to onstrut pipelines within Mexio that will link with their border rossing projet and Texas intrastate pipeline onstrution projets. Transontinental Gas Pipeline Company and Tennessee Gas Pipeline 129 Company also have several projets in the region that will benefit from and support expansions in the region. 129

135 Most of the proposed projets have been proeeding slowly for environmental, eonomi, and regulatory reasons. One obstale has been overome with the installation of Mexio s newly formed regulatory authority, the Comision de Energia (CRE). The CRE has issued less restritive regulations on foreign investment in Mexio, whih affets the ownership and operation of pipeline failities owned by others. In the fall of 1996, the CRE announed its first award of a (privatization) liense permitting the development of a loal 130 gas distribution system in the Baja area of northern Mexio. This ation may hasten the approval and final implementation of several similar loal servie development proposals, whih are linked to pending U.S. export proposals that have remained dormant for several years. In Deember 1997, onstrution was ompleted on the El Paso Energy Company s Samalayua projet, whih links Texas supply soures with ustomers in Mexio s Chihuahua State. The 45-mile, 210 MMf/d pipeline is the first pipeline loated in Mexio owned in part by a U.S. ompany. A major ustomer of the projet will be a 700 megawatt ombinedyle eletri generating plant loated in Samalayua, Mexio, whih will begin operations in late Summary The amount of new apaity proposed for development by the end of 2000 is signifiant and, if fully implemented, would represent a 9-perent inrease in intraregional apaity from the 1996 level and a 17-perent inrease in interregional apaity (Table ES1). Although it is unlikely that all proposed expansions will be ompleted, additional projets ontinue to be proposed. During 1997 and early 1998, for instane, at least 22 pipeline ompanies instituted open-season exerises for 26 projets, with the expetation that the market will support additional expansion plans. These proposals, while not all sussessful, inluded expansions in all regions of the ountry. Beyond what has already been proposed, there are areas of the ountry where additional pipeline expansion plans might develop in response to hanging market profiles and the development of new supply soures. For instane, deep-water development in the Gulf of Mexio will ontinue over the next deade and with it ould ome additional omplementary onshore expansions. In addition, the expanding prodution in areas of Texas and the Roky Mountains will plae pressure on loal pipeline systems to expand their apabilities to reah nearby and distant markets. As a onsequene, utilization rates on interonneting interstate pipelines should inrease and, in some ases, neessitate the development of new apaity on some systems. The upoming major inrease in apaity from Canada to the U.S. Midwest may also spur additional development of new pipelines, or expansions of existing lines, that an provide alternative apaity for transhipment of some of this gas to the U.S. Northeast. Already several of the proposed Midwest-to- Northeast expansion projets are premised on the assumption that exess apaity into the Chiago, Illinois, area ould develop over the next several years as new (proposed Canadian soure) pipelines are ompleted during the interim. The award was made to a onsortium onsisting of Paifi Enterprises 130 International (PEI), Enova International Corporation, and Proxima. The liense will permit the group to transport gas from PEI s loal system in lower California into the ity of Mexiali in northern Mexio. 130

136 Appendix C Changes in Natural Gas Markets This appendix presents several State summary data tables that detail energy use profiles of the geographi regions overed in this report and the availability of supplemental natural gas supplies. These tables supplement the regional tables in Chapter 5, Deliverability to Markets. These hanges reflet the shifts in onsumption patterns that have ourred as a result of market restruturing at both the national and loal levels. They also reflet hanges in market demand as a result of hanges in a State s eonomi profile during the past several years. The first table, Table C1, Regional Weather and Gas Storage Lastly, Table C4, Regional and State Natural Gas Customers, Profile, provides some basi data regarding the relative Average Annual Growth supplements Table C3 by providing seasonal temperature variation among States (a key data on the number of natural gas onsumers for eah end-use determinant of natural gas demand) and levels of underground setor in 1996 and the average annual growth rate from 1990 and liquefied natural gas (LNG) storage. How muh gas an through The hange in these fators underlies the level be delivered from storage failities and is available to the and magnitude of the movements refleted in the market pipeline network during peak periods are ruial fators in shares for natural gas ustomer groups. analyzing the ability of the pipeline system to support estimated onsumer requirements. Most of the annual data used to ompile the annual average rates of hange shown in these tables may be found in the The seond table, Table C2, Regional and State Energy following publiations: Profile Comparison of Annual Average Change, shows total the Natural Gas Annual, the Eletri Power Annual, or the energy onsumption patterns for eah of the lower 48 States, State Energy Data Report (SEDS). While the period of in partiular how the use of natural gas inreased (dereased) omparison, for the most part, was for the years 1990 through relative to all other fuel types between 1990 and The 1996, in some instanes data were not yet available for third table, Table C3, Regional and State Natural Gas Speifially, the SEDS data, whih tabulate all annual energy Customer Market Share Changes, illustrates how the use of use data on a ommon (Btu) basis, are not ompiled until all natural gas among the various natural gas ustomer setors individual fuel data are verified and omplete; they were within eah State has hanged sine available only through 1995 when this report was prepared. 131

137 Table C1. Regional Weather and Gas Storage Profile, 1996 Natural Gas Underground Storage LNG Peaking Supplies Peak-Day Withdrawal Capability (Deliverability) 1996 Number of Normal Weather Interstate Heating Ranking From From Perent Pipelines Degree Among Working Convent- High- Perent Perent LDC Operating Days States Gas ional Deliverability Interstate Operated Owned Peak-Day in (1960- (1 = Capaity Total Storage Storage Pipeline by and Capaity Support Region State 1990) Coldest) (MMf) (MMf/d) (perent) (perent) Operated Independents Operated (MMf) (MMf/d) Central Colorado 9 7, ,261 1, Iowa 4 6, ,100 1, , Kansas 9 4, ,291 2, Missouri 8 5, , Montana 5 8, , Nebraska 6 6, , , North Dakota 3 9, South Dakota 3 7, Utah 4 6, , Wyoming 6 8, , Total 21 7, ,894 6, , Midwest Illinois 9 6, ,771 6, , Indiana 7 5, , , Mihigan 6 6, ,912 11, Minnesota 5 8, , ,412 1,520 Ohio 9 5, ,379 4, Wisonsin 5 7, Total 17 6, ,130,475 24, ,722 2,685 Northeast Connetiut 3 6, , Delaware 3 4, Maine 1 7, Maryland/DC 5 4, , , Massahusetts 3 6, , New Hampsh. 1 7, New Jersey 5 5, , New York 12 5, ,889 1, , Pennsylvania 9 5, ,016 7, Rhode Island 2 5, , Vermont 2 7, Virginia 4 4, , West Virginia 5 5, ,684 3, Total 15 6, ,842 11, ,765 3,759 Southeast Alabama 9 2, , , Florida Georgia 4 2, ,756 1,122 Kentuky 9 4, ,467 1, Mississippi 14 2, ,860 3, North Carolina 1 3, , South Carolina 2 2, , Tennessee 9 3, , , Total 18 2, ,717 5, ,044 2,841 Southwest Arkansas 10 3, , Louisiana 21 1, ,110 5, , New Mexio 4 4, , Oklahoma 12 3, ,737 2, Texas 29 2, ,906 11, Total 35 3, ,532 20, , Western Arizona 2 2, California 8 2, ,276 6, Idaho 2 6, Nevada 4 4, , Oregon 2 5, , , Washington 4 5, , , Total 10 4, ,206 7, , U.S.Total ,766,666 74, ,820 11,181 MMf/d = Million ubi feet per day. LDC = Loal distribution ompany. -- = Not appliable. Soures: Normal Heating Degree Days: U.S. Department of Commere, National Oeani and Atmospheri Administration, State Regional, and National Monthly and Seasonal Heating Degree Days Weighted by Population. Natural Gas Underground Storage: Energy Information Administration (EIA), Form EIA-191, Underground Gas Storage Report. Liquefied Natural Gas (LNG): EIAGIS-NG Geographi Information System, LNG Database, as of Deember

138 Table C2. Regional and State Energy Profile Comparison of Annual Average Change, Population Overall Energy Consumption Natural Gas Consumption U.S. Natural Gas As Perent Ranking Prodution Millions Perent Quantity U.S. Perent of Total Quantity (Perent Perent (1996) as a Region / in 1995 Annual 1995 Ranking Annual Energy 1995 Gas to Annual Ratio of State (estimated) Change (trillion Btu) 1995 Change Consumed (trillion Btu) Total) Change Consumption Central Colorado 3, , Iowa 2, , Kansas 2, , Missouri 5, , Montana Nebraska 1, North Dakota South Dakota Utah 2, Wyoming Total 20, , , Midwest Illinois 11, , , Indiana 5, , Mihigan 9, , Minnesota 4, , Ohio 11, , Wisonsin 5, , Total 48, , , Northeast Connetiut 3, Delaware Maine 1, Maryland/DC 5, , Massahusetts 6, , New Hampshire 1, New Jersey 7, , New York 18, , , Pennsylvania 12, , Rhode Island Vermont Virginia 6, , West Virginia 1, Total 66, , , Southeast Alabama 4, , Florida 14, , Georgia 7, , Kentuky 3, , Mississippi 2, , North Carolina 7, , South Carolina 3, , Tennessee 5, , Total 48, , , Southwest Arkansas 2, Louisiana 4, , , New Mexio 1, Oklahoma 3, , Texas 19, , , Total 31, , , Western Arizona 4, , California 31, , , Idaho 1, Nevada 1, Oregon 3, , Washington 5, , Total 47, , , U.S. Total 263, , , = Not appliable. Soures: Natural Gas Prodution and Consumption: (EIA), Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition. Energy Consumption: EIA, State Energy Data Report, Consumption Estimates (Deember 1997). Population: U.S. Department of Commere, Bureau of the Census. 133

139 Table C3. Regional and State Natural Gas Customer Market Share Changes, Share of the Natural Gas Market Share Change Sine 1990 Average Annual Change in Consumption (perent) (perentage point) (perent) Region / State Resi- Com- Indus- Eletri Resi- Com- Indus- Eletri Resi- Com- Indus- Eletri dential merial trial Utilities Other dential merial trial Utilities Other dential merial trial Utilities Other Central Colorado Iowa a a 0 0 a Kansas a Missouri a 1 0 a Montana a Nebraska a North Dakota a a South Dakota Utah Wyoming a Total a Midwest Illinois Indiana a a a Mihigan Minnesota a -3 a Ohio a -1 1 a Wisonsin a a Total a a Northeast Connetiut b 21.6 Delaware Maine a a a Maryland/DC a Massahusetts a New Hampshire a a b New Jersey New York a Pennsylvania Rhode Island b 40.3 Vermont a b 13.5 Virginia West Virginia a -8 a Total a Southeast Alabama a a Florida a Georgia a Kentuky a Mississippi North Carolina a South Carolina b 1.7 Tennessee a a a Total a Southwest Arkansas Louisiana a a New Mexio Oklahoma Texas a a Total a a Western Arizona California Idaho a a a Nevada a Oregon Washington b 5.6 Total Total U.S a abetween plus 0.5 perent and minus 0.5 perent. bover plus or minus 100 perent per annum. Result very large (small) due to large flutuations in annual volumes reported in this ategory. Note: Totals may not equal sum of omponents beause of independent rounding. Soure:, Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition. 134

140 Table C4. Regional and State Natural Gas Customers, Average Annual Growth, Residential Customers Commerial Firms Industrial Firms Eletri Utilities Annual Change Annual Change Annual Change 1 Annual Change (perent) (perent) (perent) (perent) In In Number Number Number In In Number In In Number In In of All of Gas- In Total In Gas in Number Average in Number Average in Number Average Type Fired Summer Fired Region 1996 of Users Use 1996 of Users Use 1996 of Users Use Units Units Capaity Capaity Central Colorado 1,147, , , Iowa 771, , , Kansas 804, , , Missouri 1,275, , , Montana 205, , Nebraska 439, , , North Dakota 97, , South Dakota 127, , Utah 562, , Wyoming 131, , Total 5,562, , , Midwest Illinois 3,494, , , Indiana 1,489, , , Mihigan 2,812, , , Minnesota 1,103, , , Ohio 2,994, , , Wisonsin 1,324, , , Total 13,220, ,113, , Northeast Connetiut 433, , , Delaware 106, , Maine 14, , Maryland/DC 1,006, , Massahusett 1,188, , , New Hampsh. 75, , New Jersey 2,147, , , New York 4,048, , , Pennsylvania 2,431, , , Rhode Island 204, , Vermont 24, , Virginia 789, , , West Virginia 358, , Total 12,829, ,154, , Southeast Alabama 766, , , Florida 521, , Georgia 1,538, , , Kentuky 696, , , Mississippi 418, , , North Carolina 699, , , South 426, , , Tennessee 841, , , Total 5,908, , , Southwest Arkansas 539, , , Louisiana 945, , , New Mexio 428, , , Oklahoma 866, , , Texas 3,501, , , Total 6,282, , , Western Arizona 689, , California 8,969, , , Idaho 187, , Nevada 393, , Oregon 433, , Washington 673, , , Total 11,347, , , Total U.S. 55,151, ,704, , Inludes both primary and seondary generating units = Not appliable. Soure: Natural Gas Usage: (EIA), Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition. Eletri Generation Capaity: EIA, Form EIA-860, Annual Eletri Generation Report, 1990 through

141 136

142 Appendix D Data Soures The data presented in the body of this report ame from many measure is likely to be sustainable for more than a short soures and often required some adjustment to provide period of time. information on a omparable basis for use in the analysis. This appendix provides detailed information on the Information on apaity levels for the interstate pipeline methodology and soure material used to develop estimates systems is generally available from filings at the Federal of interstate pipeline apaity at State borders and the hanges Energy Regulatory Commission (FERC). However, this in energy usage patterns from 1990 through information is typially assoiated with ompressor stations and not State border apaity. Thus, to estimate the The following is a list of the data soures disussed in this State-to-State apaities on the pipelines, an approah was appendix. required. Further, while there is a regulatory requirement for the submission of design information, the terminology Annual pipeline ompany reports filed with the Federal provided in the submissions sometimes is unlear as to Energy Regulatory Commission (FERC) under 18 CFR whether the data provided by a ompany are in fat the , Peak-Day Capaity Report, and 260.8, information requested. Format FERC 567, System Flow Diagrams. The original ompilation of pipeline apaity estimates was FERC Form 2, Annual Report of Major Natural Gas done by the during 1991 Companies and 1992, using 1990 as the base year. The initial approah taken to derive the State-to-State apaity information was the FERC Form 11, Natural Gas Pipeline Monthly following: Statement, 1995 and earlier years. (The survey beame a quarterly report in 1996.) Develop initial apaity estimates by using ompressor station data from FERC Format 567, "System Flow FERC Index of Customers Diagrams." (EIA), Form Adjust initial estimates by using delivery requirements of EIA-176, Annual Report of Natural and Supplemental ustomers loated between the State line and the station Gas Supply and Disposition and for any ontrated reeipts from other pipelines., Form EIA-191, When ompressor station data were unavailable on Underground Natural Gas Storage Report Format 567, derive a statistial estimate by using a regression equation based upon the diameter(s) of the Natural Gas Annual, DOE/EIA-0130, various issues. pipeline segment in question. Pipeline Capaity The measure of pipeline apaity that was estimated and addressed in this report is the daily apaity of the interstate natural gas pipeline network at regional and State boundaries. Speifially, it is an estimate of the maximum volume of gas that an be transported under normal operating onditions for a sustained period of time. While pipeline systems have onsiderable operational flexibility to inrease deliveries of natural gas above design apaity levels to ertain areas for short periods of time, this often means that deliveries are redued elsewhere or that line paking ours. Neither Impute remaining missing values by using proxies for apaity. Data used for this purpose inlude ontrat demand (CD) data for pipeline sales ustomers, whih were available for the years 1988 and (CD data were no longer available one FERC Order 636 was implemented in November 1993.) Cross hek the State border apaities for reasonableness by using ontrat demand levels (if not used as a proxy for apaity); flow data from Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition ; and onsultations with FERC staff and ompany offiials. 137

143 annual FERC Format 567 System Flow Diagram for eah pipeline system were ompared with the previous year s submission. The primary items examined were the throughput apabilities of the pipeline s ompressor stations and whether they had inreased, had hanged, or had new stations added. In addition, omparisons of reeipt and delivery point volumes were also performed to determine hanges in peak- day deliverabilities and as a replaement for ontrat demand data whih were no longer urrent. Available data on pipeline onstrution projets ompleted during the interim were also fatored into any estimate adjustments. These omparisons were done, to the extent possible, through omparative analyses of updated databases. Initial estimates of revised apaity levels were produed and displayed on annotated pipeline maps. The initial (1990) estimates of apaity on a pipeline segment at a State border were based on reported ompressor station throughput, the daily output of whihever ompressor station appeared to be losest to the State border. The working assumption was that throughput apability, even if only an estimated flow under urrent operating onditions, of any ompressor station is a reasonably good estimate of peak-period throughput at that point on the line. (Note: Compressor station output may be a onstraint on throughput when downstream pipeline diameter and other harateristis of the segment may allow the physial pipeline to handle greater loads than required under urrent ustomer peak-day ommitments. Conversely, the designed ompressor output may be greater than an be sent through existing pipeline onfigurations.) When no delivery or reeipt points were between the seleted ompressor station and the State line, the apaity at the State border was assumed to equal the station apability, even though some frition losses would our beause of the distane between the line and ompressor. When data were available for both reeipt and CD deliveries between the ompressor station and the State line, then the initial apaity estimates were adjusted to aount for these volumes. In some ases, peak-day information rather than design apaity was reported on the Format 567. These estimates were onsidered a reasonable proxy for apaity. Under ertain onditions, ontrat demand data were used to estimate apaity levels at a State border. CD data were assumed to be a reasonable refletion of urrent peak-day demands on the pipeline system and, therefore, a lose approximation of the apability or apaity of the pipeline to supply those ustomers. A pipeline's CD ommitment levels within a State were used as a surrogate for a measure of that pipelines' apaity into the State when the pipeline system, or a branh, terminated in the State. Even in this instane, however, the pipeline ompany ould meet a portion of its ommitments from soures within the State borders. In some ases, ompressor station data and ontrat demand data were inadequate to develop an initial apaity estimate, and other methods were pursued to make the initial apaity estimate. For instane, regression equations to estimate apaity were developed by use of a universe of 814 ompressor stations with known pipeline diameters, apaities, and pressures, extrated from the Format 567 filings. The results indiated that diameter alone was a good preditor of apaity in these equations. Subsequently, updated annual apaity estimates were developed for years 1991 through 1996 by using the 1990 levels as starting points. First, the ontents of the most reent These estimates were then presented to the pipeline ompany or FERC staff for evaluation. These inputs were used to settle upon a final estimate. Average Daily Pipeline Flow The data soure for atual average daily pipeline volume flows aross State borders was Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition. In addition, these data are the basis for Statelevel supply, onsumption, and transportation volumes presented in this report. The respondent universe of the Form EIA-176 inludes interstate and intrastate pipeline ompanies; investor and muniipally owned natural gas distributors; underground natural gas storage operators; syntheti natural gas plant operators; and field, well, or proessing plant operators that deliver natural gas diretly to onsumers and/or transport gas to, aross, or from a State border through field or gathering lines. The average daily flow volumes presented in the Region-to- Region Capaity tables in the report are based upon preliminary 1996 data from Form EIA-176. They are the sum of data that an be identified as volumes brought aross a border: on-system purhases reeived at a State border, plus transportation and/or exhange reeipts reeived at a State line, plus transported into the report State. The data on Form EIA-176 are annual; average daily levels were omputed on a 366-day basis (1996 was a leap year). Greater detail onerning Form EIA-176, its bakground, and EIA proessing methodology, may be found in the EIA publiation Natural Gas Annual 1996, DOE/EIA-0131, Appendix A. 138

144 System Flow Rate Data The pipeline systemwide flow rate data disussed in this report (detailed in Appendix A) and used for utilization analyses are based on monthly throughput volume data reported on FERC Form 11, Natural Gas Pipeline Monthly Statement. These data for the period January 1980 through Deember 1995 are maintained and available on omputer tape. Transportation, sales, and interompany transfer throughput volumes are reported, but for the total pipeline system only. As a result, these data annot be used to ompute regional or State-level utilization levels. However, the historial data were used to identify and quantify the largest monthly throughput level ourring on the individual pipeline systems over the period 1980 through Average monthly throughput rates for 1989 and 1995 were then divided by the largest monthly throughput (whih was used as an approximation of a 100-perent load fator or a surrogate measure for full apaity utilization) to estimate the overall relative flow rate (throughput) on the various pipeline systems in Transportation System Aess The analysis of transportation system aess (Chapter 5) employed a sample of 46 major interstate natural gas pipeline ompanies. The sample was seleted to ensure that adequate and uniform peak-day and monthly transportation information was available for eah pipeline ompany. All pipeline ompanies in the sample were required to have at least three of the four peak-delivery data neessary to determine maximum apability. The data used in the derivation of maximum apability are from the pipeline ompany reports filed with the Federal Energy Regulatory Commission (FERC). These data inlude: the estimated peak-day apaity of the pipeline ompany s system from the 1996 Peak-Day Capaity Report (18 CFR ); the quarterly ontrated firm transportation apaity from the quarterly Index of Customers filings for the period April 1, 1996, through April 1, 1997; the oinident peak-day delivery from the 1995 FERC Format 567 System Flow Diagrams ; and the transmission system peak deliveries from the 1996 filing of FERC Form 2, Annual Report of Major Natural Gas Companies. In addition to having suffiient information to estimate maximum apability, the analysis required that eah pipeline ompany in the sample had filed FERC Form 11, Natural Gas Pipeline Company Quarterly Statement of Monthly Data, for the period April 1996 through Marh The transportation volumes from FERC Form 11 were used to assess the utilization of the reserved apaity. This report also uses data from the FERC Form 2, Annual These data requirements resulted in a sample size that was Report of Major Natural Gas Companies, for disussions 17 pipeline ompanies smaller than the sample seleted for pertaining to system peak-day deliverability rates and the analysis of firm apaity ontrats, also in Chapter 5. utilization levels on those days. These data, whih are Although the aessibility analysis used 32 perent fewer reported on page 518, Transmission System Peak Deliveries pipeline ompanies than the sample for the ontrat analysis, of FERC Form 2, provide peak delivery volumes at several nd it exluded only 1 perent, or 1.4 quadrillion Btu per day, of levels. Those periods are: highest day, 2 highest, and rd the firm ontrated apaity (based on the April 1, 1997, 3 highest days deliveries, highest 3 onseutive days, and FERC Index of Customer filing) inluded in the firm ontrat highest month deliveries. These data are to be reported for the analysis. period during the twelve months embraing the heating season overlapping the year s end for whih this report is submitted. The latest suh period available for this report Firm Capaity Contrats was the heating year (April 1995 through Marh 1996). The FERC Index of Customers filing was the prinipal soure of information for the analysis of firm apaity ontrats in The peak-day (highest one day) deliveries reported on FERC Chapter 5. The guiding prinipal for the analysis was to Form 2 were used in relation to system apaity levels assemble the most reent, reliable information available. reported on the annual pipeline ompany reports filed with the Therefore, the quarterly FERC Index of Customers filings for FERC under 18 CFR The omparison of the two April 1, 1996, through April 1, 1997, were used for the items provides some insight into the systemwide level of analysis. Several pipeline ompanies were exluded from the pipeline usage during periods of highest user need and some filed Index of Customers beause their data were inonsistent indiation of how well the system is able to meet its or missing. The resulting sample onsists of 63 interstate obligations to its ustomers under urrent apaity limitations. pipeline ompanies. Sine the analysis was not onerned with onsisteny aross several soures of information, it employed a muh larger sample of pipeline ompanies than the aessability analysis. Firm transportation apaity was examined by type of shipper. Pipeline ompanies are required to dislose the amount of apaity reserved by eah firm ustomer in the 139

145 quarterly Index of Customers filing to the Federal Energy Regulatory Commission. The Index of Customers provides the name of eah ompany that ontrated for firm transportation, but it does not provide any other information to identify what type of ompany eah shipper was. Thus, EIA staff ompared shipper names with lists of ompanies from other soures to lassify eah shipper. Four soures were used for omparison: (1) Form EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition ; (2) Benjamin Shlesinger and Assoiates, In., Diretory of Natural Gas Marketing Servie Companies, Eleventh Edition (May 1997) (a proprietary soure); (3) Energy Planning, In., Diretory of Natural Gas Consumers, 5th Edition (1996) (a proprietary soure); and (4) Form EIA-860, Annual Eletri Generator Report. The list of eletri utilities from Form EIA-860 inluded ombination eletri and gas utilities. Shippers that appeared in this list and that used natural gas as either the primary or alternative soure of fuel for eletriity generation were lassified as eletri utilities, even the ombination ompanies. Combination ompanies that did not use natural gas as the primary or alternative soure of fuel for eletriity generation were lassified as loal distribution ompanies. For example, Baltimore Gas and Eletri Company was lassified as an eletri utility while Atlanta Gas Light Company was lassified as a loal distribution ompany. The final set of shipper ategories is as follows: Eletri utilities (inluding ombination eletri and natural gas utilities for whih natural gas is the primary or alternative soure of fuel for generating eletriity) Industrial ompanies (inluding independent power produers, ogenerators, and ommerial firms) Loal distribution ompanies (inluding intrastate pipeline ompanies and ombination eletri and natural gas utilities for whih natural gas is not the primary or alternative soure of fuel for generating eletriity) Marketers Interstate pipeline ompanies Other ompanies (inluding produers and gatherers and ompanies that ould not otherwise be lassified). Underground Natural Gas Storage Data Eah month, on the s Form EIA-191, Underground Natural Gas Storage Report, U.S. storage operators are required to report their urrent estimates of injetions and withdrawals ourring in the previous month at eah site they operate. In addition, on an annual basis, eah operator is expeted to report any hange to total, base, or working gas apaity, as well as daily deliverability (see Glossary) that may have ourred at the site during the previous alendar year. These data have been ompiled in a database with eah site identified by suh riteria as ownership type (interstate pipeline, loal distribution ompany, or independent operator), type of faility (depleted reservoir, salt avern, aquifer, or mine), and interonneting pipeline. The ombination of this information, in assoiation with the apability (apaity level) of onneting pipeline systems, with an approximate loation, permitted an analysis and a way of estimating the impat of storage availability and operational apability on servie to produers and shippers and pipeline utilization. Maps and Mapped Data The geographi displays in this report were produed, in whole or in part, using the EIAGIS-NG Geographi Information System. The system onsists of a series of sitespeifi databases and digitized pipeline maps residing in a personal omputer (PC) environment. The pipeline map files were developed from publily available soures, although in some ases, more detailed maps were provided by the individual pipeline ompanies. Currently, the EIAGIS-NG ontains map data for 61 interstate and 71 intrastate pipeline ompanies loated in the United States, and 18 interstate pipeline ompanies loated in Canada. Many of the interstate pipeline map files also ontain profile (attribute) data for eah pipeline segment, suh as pipe diameter, maximum allowable pressure, looping, et. These data were ompiled from the pipeline system shemati ontained in the Form FERC-576, System Flow Diagram. The individual databases supporting the system inlude the following pipeline-related data: 140

146 Compressor stations Delivery points Reeipt points Major interonnetions State border rossings and apaity levels. Nonpipeline-related databases inlude: Underground storage sites Planned underground storage projets Proposed onstrution projets Loal distribution ompany servie areas Export and imports Market enters/hubs Eletri power plants, et. The prinipal geographi data used in this report to ompile apaity estimates were the pipeline maps and their reeipt, delivery, interonnetion, and ompression station points. Planned and existing underground storage site data were used to develop estimates of supplemental peak-day deliverability to the pipeline network. U.S. Regional Definitions The six U.S. regions used in this report were based in whole or in part upon the 10 Federal regions originally defined by the Bureau of Labor Statistis. The groupings are as follows: Northeast Region Federal Region 1: Connetiut, Maine, Massahusetts, New Hampshire, Rhode Island, and Vermont. Federal Region 2: New Jersey, and New York. Federal Region 3: Delaware, Distrit of Columbia, Maryland, Pennsylvania, Virginia, and West Virginia. Southeast Region Federal Region 4: Alabama, Florida, Georgia, Kentuky, Mississippi, North Carolina, South Carolina, and Tennessee. Midwest Region Federal Region 5: Illinois, Indiana, Mihigan, Minnesota, Ohio, and Wisonsin. Southwest Region Federal Region 6: Arkansas, Louisiana, New Mexio, Oklahoma, and Texas. Central Region Federal Region 7: Iowa, Kansas, Missouri and Nebraska. Federal Region 8: Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming. Western Region Federal Region 9: Arizona, California, and Nevada. Federal Region 10: Idaho, Oregon, and Washington. 141

147 Glossary appliation for the Certifiate of Publi Conveniene and Neessity at the Federal Energy Regulatory Commission. Generally, the ertifiated apaity represents a minimum level of servie that an be maintained over an extended period of time and does not always represent the maximum throughput apability of the system on any given day. Citygate: Loation where gas is delivered to a loal distribution ompany by a pipeline transmission ompany. Cogeneration: The prodution of steam (usually by natural gas), in onjuntion with industrial operations or other non- utility gas-burning funtions, whih is used to power generators for the seondary prodution of eletriity. Coinidental Peak-Day Flow: The volume of gas that moves through a pipeline or setion thereof or is delivered to a ustomer on the day of the year when the pipeline system handles the largest volume of gas. Abandonment: Regulatory permission to disontinue servie by removing various failities from the transmission and distribution system or to stop transporting gas to or for speifi ustomers or to ertain areas. For instane, to disontinue storage servies, well prodution, or gathering systems. Affiliated Company: A ompany that is either diretly or indiretly ontrolled and/or owned by another firm or holding ompany. Alternate Reeipt and Delivery Points: Loations other than the primary points speified in a ontrat at whih a shipper an shedule delivery on a firm basis. Alternative Fuel Capaity: The on-site availability of apparatus to burn fuels other than natural gas. Assoiated-Dissolved Gas: Natural gas produed in assoiation with oil, also known as asinghead gas. Baseload: A volume of gas that serves as a onstant load over a period of time. Blanket Certifiate (Authority): Permission granted by the Federal Energy Regulatory Commission (FERC) for a ertifiate holder to engage in an ativity (suh as transportation servie) on a self-implementing or prior notie basis, as appropriate, without ase-by-ase approval from FERC. Btu: Abbreviation for British thermal unit. The quantity of heat needed to raise the temperature of 1 pound of water by 1 degree Fahrenheit at a speified temperature and pressure (from 59 degrees Fahrenheit to 60 degrees Fahrenheit at an atmospheri pressure of inhes of merury). Capaity Release Market: Where natural gas shippers may offer the rights of some or all of their firm apaity in exhange for revenue redits. Capaity Turnbak: When natural gas shippers, upon expiration of their ontrat(s) for pipeline apaity do not renew apaity rights, in whole or in part, with the original pipeline. Certifiated Capaity: The apability of a pipeline projet to move gas volumes on a given day, based on a speifi set of flowing parameters (operating pressures, temperature, effiieny, and fluid properties) for the pipeline system as stated in the dokets filed (and subsequently ertified) in the Combined-Cyle Generation: System for generating eletriity by use of a gas turbine or a heat reovery boiler and a steam turbine in tandem. Commerial Servie: Natural gas servie to restaurants, retail stores, shools, institutions, et. Compressor Station: An installation loated on a pipeline system and whih ontains engine- or turbine-driven ompressors used to move natural gas through a pipeline by raising the pressure applied to the flow of gas. The apabilities of the station are defined primarily by level of installed horsepower and designed daily gas throughput apaity. Contrat Demand: The level of firm servie in terms of the maximum daily and/or annual volumes of natural gas sold and/or moved by the pipeline ompany to the ustomer holding the ontrat. Failure of a pipeline ompany to provide servie at the level of the ontrat demand speified in the ontrat an result in a liability for the pipeline ompany. Cushion (Base) Gas: The volume of gas, inluding native gas, needed as a permanent inventory in a storage reservoir in order to maintain adequate reservoir pressure and deliverability rates. Daily Average Flow: The volume of gas that moves through a setion of pipe determined by dividing the total annual volume of gas that moves through a setion of pipe by 365 days. Volumes are expressed in million ubi feet per day measured at a pressure of psia and a temperature of 60 degrees Fahrenheit. For pipes that operate with bidiretional flow, the 143

148 volume used in omputing the average daily flow rate is the volume assoiated with the diretion of flowing gas on the peak day. Deliverability: Refers to the volumes of natural gas that may be transferred at a designated point on the transportation network. The speifi volume level is normally stated on a peak-day apability basis and is a funtion of faility (system) design, whih itself is premised upon atual or estimated market demand requirements. Pipeline network deliverability in this analysis is prediated upon a summary measure of pipeline apaity at regional and/or State boundaries. Pipeline apaity is, in part, a funtion of the number of pipes, their diameter, ompression, and operating pressure situated at the transfer point. Deliverability from storage represents a volume level that may be transferred to the pipeline network on a peak day to supplement the pipeline apaity serving the regional market. Deliverability (from storage): The output of gas from a storage reservoir, as expressed as a rate in thousand ubi feet (Mf) per 24 hours, at a given total volume of gas in storage with a orresponding reservoir pressure and at a given flowing pressure at the wellhead. Design Capaity: See ertifiated apaity. The design apaity of pipeline setions having bidiretional flow is the apaity assoiated with the diretion of the flow observed on the peak day. Design Day: A 24-hour period of demand whih is used as a basis for planning gas apaity and servie requirements. Downstream Pipeline (State): A pipeline (State) loser to the market area, as opposed to an upstream one, whih is loser to the prodution area. Federal Energy Regulatory Commission (FERC): The Federal ageny with jurisdition over natural gas priing, wholesale eletri rates, hydroeletri liensing, oil pipeline rates, and gas pipeline ertifiation. Enhaned Oil Reovery: Use of steam injetion, most often produed by burning natural gas as a seondary or tertiary oil reovery method. Eletriity ogeneration is usually a by-produt of suh operations. Extration Plant: A proessing plant that is used for the separation of liquid hydroarbons from a natural gas stream. Firm Servie: Servie offered to ustomers (regardless of lass of servie) under shedules or ontrats whih antiipate no interruptions. The period of servie may be for only a speified part of the year as in off-peak servie. Certain firm servie ontrats may ontain lauses that permit unexpeted interruption in ase the supply to residential ustomers is threatened during an emergeny. Gathering System: A network of small pipelines whih onnet produing wells with a transmission system. Gas Turbine: Power equipment of the turbine type whih utilizes the gas ombustion as a motive fore. Grid (Transmission) System: Natural gas pipeline system haraterized by a large number of laterals or branhes from the mainline that tend to form a network of integrated reeipt, delivery, and pipeline interonnetions operating in and serving major market areas. Similar to a loal distribution ompany (LDC) network onfiguration but on a muh larger sale. Heating Degree Day: An index indiating the differene between 65 degrees Fahrenheit and the average temperature for a day, where the average temperature is the average of the day's high and low temperatures. If a day's average temperature were 45, there would be 20 degree days for the date. If the average temperature were above 65 degrees Fahrenheit, then the heating degree day would equal zero. Industrial Servie: Natural gas servie to fatories, mines, pulp mills, smelters, et. Infill Drilling: There are two types of infill drilling: (1) The drilling of additional wells in a developed field in an effort to inrease total ultimate reovery; and (2) drilling a replaement well within a proration unit, after the original well has been plugged and abandoned, in order to enter a new reservoir that ould not be reahed or drained by reompletion. Interruptible Servie: A sales volume or pipeline apaity made available to a ustomer without a guarantee for delivery. "Servie on an interruptible basis" means that the apaity used to provide the servie is subjet to a prior laim by another ustomer or another lass of servie (18 CFR 284.9(a)(3)). Gas utilities may urtail servie to their ustomers who have interruptible servie ontrats to adjust to seasonal shortfalls in supply or transmission plant apaity without inurring a liability. Interstate Pipeline: A natural gas pipeline ompany that is engaged in the transportation, by pipeline, of natural gas aross State boundaries, and is subjet to the jurisdition of FERC under the Natural Gas At. Intrastate Pipeline: A natural gas pipeline ompany engaged in the transportation, by pipeline, of natural gas not subjet to the jurisdition of FERC under the Natural Gas At. 144

149 Lateral: A setion of natural gas pipeline that branhes off from the mainline to onnet with or serve a speifi ustomer or group of ustomers. LDC: Loal Distribution Company. A natural gas utility ompany whih reeives gas from a mainline transmission pipeline ompany and distributes same to the ultimate onsumer. Line Paking: Inreasing the amount of gas in the system or pipeline segment by temporarily inreasing pressure to meet high demand for a short period of time. Often exerised overnight as a temporary storage medium to meet antiipated next-day peaking demands. Liquefied Natural Gas (LNG): Natural gas that has been subjeted to high pressure and very low temperatures and stored in a liquid state. It is returned to a gaseous state by the reverse proess and used as a peaking fuel. Load Balaning: Maintaining system integrity through measures whih equalize pipeline (shipper) reeipt volumes with delivery volumes during periods of high system usage. Withdrawal and injetion operations into underground storage failities are often used to balane load on a shortterm basis. Load Fator: The ratio of average daily deliveries to peak-day deliveries over a given time period. Looping: Inreasing apaity on a pipeline system or segment by adding another pipeline running parallel to existing lines. Mainline (Transmission Line): The wide-diameter, oftentimes long-distane portion of a natural gas pipeline system, exluding laterals, loated between the gathering system (prodution area) or gas-proessing plant and other reeipt points and the prinipal ustomer servie area(s). Market Center/Hub: A transfer site or system where several interstate and/or intrastate natural gas pipelines interonnet and where shippers may obtain servies to manage and failitate their routing of supplies from prodution areas to markets. Title transfer, temporary storage, and imbalane management are some of the servies usually available at suh failities. Marketed Prodution: Gross withdrawals from gas/oil wells less gas used for repressuring, quantities vented and flared, and nonhydroarbon gases removed in treating or proessing operations. Native Gas: The volume of gas remaining in a reservoir after eonomi prodution eases and before onversion to use as a storage site. NGPA Setion 7 Authority: Setion 7 of the Natural Gas At of 1938 requires an interstate pipeline ompany to justify and aquire a ertifiate of publi need and onveniene before onstruting failities to transport gas. Pipeline ompanies may expand or onstrut failities used solely to enable this transportation servie, subjet to ertain onditions and reporting requirements. NGPA Setion 311: Setion 311 of the Natural Gas Poliy At of 1978 allows an interstate pipeline ompany to transport gas on behalf of any intrastate pipeline or loal distribution ompany. Pipeline ompanies may expand or onstrut failities used solely to enable this transportation servie, subjet to ertain onditions and reporting requirements. No-notie Servie: A bundled, itygate firm servie under Order 636 that allows ustomers to reeive gas on demand to meet peak servie needs subjet to delivering supplies into the pipeline under a pak or draft order and without paying daily balaning and sheduling penalties. Nonassoiated Gas: Natural gas produed from gas wells that do not ontain or produe oil. Nonoinidental Peak-Day Flow: The largest volume of gas delivered to a partiular ustomer by a pipeline ompany in a single day during the year. Off-Peak Period: Period of low ontrat demand, suh as during the summer months in northern limates but may also apply to periods as short as ertain periods of a day when usage is low. Off-Peak Servie: Servie made available on speial shedules or ontrats, but only for a speified part of the year during the off-peak periods. Open-Aess Transportation: The ontrat arriage delivery of nonsystem supply gas on a nondisriminatory basis for a fee. Generally subjet to transportation tariffs, whih are usually on an interruptible servie basis on first-ome, first-serve apaity usage. Open Season: A period (often 1 month) when a pipeline offers to aept bids from shippers and others for potential new transportation apaity. Bidders may or may not have to provide earnest money, depending upon the type of open season. If enough interest is shown in the announed new apaity, the pipeline will refine the proposal and prepare an appliation for 145

150 onstrution before the appropriate regulatory body for approval. Operator: The person or firm responsible for the day-to-day operation of a plant or faility. Optional Certifiate (formerly known as Optional Expedited Certifiate (OEC)): In 1987, FERC issued Order 500, whih eliminated the requirement for FERC approval as to the finanial soundness of a onstrution projet if the pipeline ompany were willing to aept the market rate of return for the projet. Peak or Peak Load: The maximum demand for gas on a system during a speified interval: hour, week, month, or year. Peak Shaving: Injetion of supplemental supplies of natural gas, suh as from underground storage or liquefied natural gas (LNG) failities, into the pipeline system during periods of maximum demand. Also applies to the at of installing suh failities as a way of avoiding expanding (or building) the prodution-to-market apaity of the system to aommodate fully the potential maximum demand loads on the basi system. Pipeline Sales Servie: Before 1992, interstate pipeline ompanies provided bundled sales and transportation servie at regulated rates. This bundled servie was disontinued in 1993, for most ustomers, by Order 636, whih allowed pipeline ompanies to sell unbundled gas at market-based rates. Order 636-A required pipeline ompanies to ontinue bundled sales servie to their existing small ustomers at ost-based rates for a transitional 1-year period. Psia: Pounds per square inh at atmospheri pressure. Servie Agreement: An agreement between a natural gas ompany and a gas purhaser or shipper speifying the servie to be rendered, area to be served, maximum obligation to deliver, delivery points, delivery pressure, appliable rate shedules by referene to the tariff, effetive date and term, and identifiation of any prior agreements being superseded. Spot Market: A market for the buying and selling of short-term natural gas ontrats, often for 30 days or less (although ontrats as long as 1 to 2 years are sometimes ategorized as short-term), usually on an interruptible or best-efforts basis. Storage (Reservoir) Operating Capaity: The maximum volume of gas an underground storage reservoir an store, limited by suh fators as failities, operational proedures, onfinement, and geologial and engineering properties. This should inlude all native gas (reoverable and unreoverable), ushion (base) gas, and working (urrent) gas. System Supply: Gas supplies purhased, owned, and sold by the supplier or loal distribution ompany to the ultimate end user. System gas is subjet to FERC or State tariff and is generally sold under long-term (ontrat) onditions. Throughput: Atual or estimated volume of natural gas that may be arried on a pipeline over a speified period of time. Total Storage Capaity: The sum of working (urrent) gas apaity and the ushion (base) gas that must remain in the storage reservoir for purposes of pressure maintenane. Trunkline (Transmission) System: Long-distane, widediameter pipeline system that generally links a major supply soure with a major market area or with a major pipeline/ldc serving a market area. Trunklines tend to have only a few reeipt points (usually at the beginning of its route), few delivery points or interonnetions with other pipelines, and few, if any, assoiated lateral lines. Also see mainline. Upstream Pipeline: A pipeline, or portion thereof, whih is loser to the prodution area or primary reeipt point for gas supplies. Utilization Rate: Daily flow (throughput) as a perent of estimated apaity. For a segment of pipe, the average-day utilization rate equals the average-day flow divided by the estimated apaity. Working (Current) Gas: The volume of gas in an underground storage reservoir in exess of total ushion (base) gas and whih is available for delivery (withdrawal). 146