DOE/EIA-0618(98)

Distribution Category UC-950

Deliverability on the Interstate

 Natural Gas Pipeline System

May 1998

Energy Information Administration

  	
 	


 	
 


	


   

This report was prepared by the Energy Information Administration, the independent statistical and analytical agency within

the Department of Energy. The information contained herein should not be construed as advocating or reflecting any policy

position of the Department of Energy or any other organization.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System iii

Preface

Deliverability on the Interstate Natural Gas Pipeline System Administration (EIA), Form EIA-176, “Annual Report of

examines the capability 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 capacity levels and utilization rates of major Report.” Complementary data were obtained primarily from

interstate pipeline companies in 1996 and the changes since the EIA, Natural Gas Annual 1996, DOE/EIA-0131(96) or

1990, as well as changes in markets and end-use consumption earlier issues.

patterns. It also discusses the effects of proposed capacity

expansions on capacity levels. Deliverability on the Interstate Natural Gas Pipeline System

The report consists of five chapters, several appendices, and direction of Kenneth A. Vagts (202/586-6401). General

a glossary. Chapter 1 discusses some of the operational and information concerning this report may be obtained from Joan

regulatory features of the U.S. interstate pipeline system and E. Heinkel (202/586-4680), Director of the Natural Gas

how they affect overall system design, system utilization, and Division. Detailed questions on specific sections of the

capacity expansions. Chapter 2 looks at how the exploration, publication may be addressed to the following analysts:

development, and production of natural gas within North

America is linked to the national pipeline grid. Chapter 3  Chapter 1. “Introduction,” James Tobin (202/586-4835).

examines the capability of the interstate natural gas pipeline

network to link production areas to market areas, on the basis  Chapter 2. “Access to Supplies and Production Regions,”

of capacity and usage levels along 10 corridors. The chapter William A. Trapmann (202/586-4835).

also examines capacity expansions that have occurred since

1990 along each corridor and the potential impact of proposed  Chapter 3. “Deliverability on the Interstate Network,”

new capacity. James Tobin.

Chapter 4 discusses the last step in the transportation chain,  Chapter 4. “Deliverability to Markets,” James Tobin.

that is, deliverability to the ultimate end user. Flow patterns

into and out of each market region are discussed, as well as

the movement of natural gas between States in each region. Mariner-Volpe (202/586-5878) and Mary E. Carlson

Chapter 5 examines how shippers reserve interstate pipeline (202/586-4749).

capacity in the current transportation marketplace and how

pipeline companies are handling the secondary market for The overall scope and content of the report was supervised by

short-term unused capacity. Four appendices provide James Tobin. Overall coordination of the report was provided

supporting data and additional detail on the methodology used by James Thompson. Significant analytical contributions were

to estimate capacity. made by the following individuals:

The main data sources (see Appendix D) used for the analysis Jay K. Mitchell—Chapter 2

include: (1) annual capacity reports and accompanying

Format 567, “System Flow Diagrams,” filed with the Federal Michael J. Tita—Chapter 5

Energy Regulatory Commission (FERC) by major interstate

pipeline companies (18 CFR §284.12 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.

was prepared by the EIA, Office of Oil and Gas, under the

 Chapter 5. “Access to Transportation Markets,” Barbara
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System v

Contents

Page

Executive Summary .............................................................................. vii 

1. Introduction ................................................................................... 1

Report Purpose and Structure ...................................................................... 1

Defining Deliverability ........................................................................... 2

Shipper Requirements ........................................................................... 4

Transmission System Design ...................................................................... 5

Pipeline Utilization .............................................................................. 7

Capacity Expansion ............................................................................. 8

2. Access to Supplies and Production Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

U.S. Natural Gas Supplies by Region, 1990-2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Receipt Capabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

3. Deliverability on the Interstate Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Recent Changes Affecting the Pipeline Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

System Growth Since 1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Major Transportation Corridors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

4. Deliverability to Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Major Market Changes, 1990-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Regional Overviews . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

5. Access to Transportation Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Estimating Capacity Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Transportation Market Activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

Characteristics of Firm Capacity Held by Different Types of Shippers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

Appendices

A. State-to-State Natural Gas Pipeline Capacity and Usage Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

B. Natural Gas Pipeline and System Expansions, 1997-2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

 C. Changes in Natural Gas Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

 D. Data Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143
Energy Information Administration

vi Deliverability on the Interstate Natural Gas Pipeline System

Tables

1. Forty Largest Interstate Pipeline Companies by Level of Deliverability, 1996 ........................... 3

2. Natural Gas Production and Supplies in the Lower 48 States, by Region, 1990-2000 . . . . . . . . . . . . . . . . . . . . . . 13

3. Lower 48 Dry Natural Gas Proved Reserves and Reserves-to-Production Ratio, 1990-1996 . . . . . . . . . . . . . . . . 15

4. Central and Western Gulf of Mexico Lease Sales Before and After the Royalty Relief Act . . . . . . . . . . . . . . . . . 17

5. Top 10 Fields in the Lower 48 States Ranked by Natural Gas Production, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . 18

6. U.S. Natural Gas Productive Capacity Utilization and Surplus Deliverability by Region, 1990, 1995, and 1996 . 18

7. Interregional Pipeline Export Capacity, Average Daily Flows, and Usage Rates, 1990 and 1996 . . . . . . . . . . . . . 35

8. Natural Gas Transportation Corridors and Associated Major Pipeline Systems, 1996 . . . . . . . . . . . . . . . . . . . . . . 38

9. Interregional Pipeline Capacity, Average Daily Flows, and Usage Rates, 1990 and 1996 . . . . . . . . . . . . . . . . . . . 53

10. Regional Weather and Gas Storage Profile, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

11. Regional Energy Profile Comparison of Annual Average Change, 1990-1995 or 1990-1996 . . . . . . . . . . . . . . . . 54

12. Regional Natural Gas Customer Market Share Changes, 1990-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

13. Regional Natural Gas Customers, Average Annual Change, 1990-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

14. Reserved Firm Transportation Capacity by Region, July 1996 and January 1997 . . . . . . . . . . . . . . . . . . . . . . . . . 81

15. Characteristics of Firm Contract Capacity as of April 1, 1997, by Shipper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Figures

1. Generalized Schematic of Natural Gas Pipeline Transmission ........................................ 6

2. Major Natural Gas Producing Basins and Transportation Routes to Market Areas . . . . . . . . . . . . . . . . . . . . . . . . 12

3. Lower 48 Natural Gas Production by Region, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

4. U.S. Coalbed Methane Output, 1990-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

5. Comparison of Average U.S. Natural Gas Wellhead Price and Canadian Natural Gas Import Price, 1990-1996 . 22

6. Canadian Gas Exports to the United States and Total Canadian Gas Production, 1990-1996 . . . . . . . . . . . . . . . . 23

7. Finding Costs for Natural Gas and Crude Oil, 1981-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

8. Offshore and Onshore Production Costs for Natural Gas and Crude Oil, 1995 and 1996 . . . . . . . . . . . . . . . . . . . 27

9. Depth Records in Deep Water Gulf Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

10. Capacity of New Natural Gas Pipeline Systems Placed in Service in the United States Between 1990 and 1997 . 33

11. Region-to-Region Natural Gas Pipeline Capacity, 1990 and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

12. Major Natural Gas Transportation Corridors in the United States and Canada, 1997 . . . . . . . . . . . . . . . . . . . . . . . 36

13. Net Natural Gas Pipeline Capacity Entering (-Exiting) Each Region, December 1997 . . . . . . . . . . . . . . . . . . . . . 52

 14. Interstate Natural Gas Capacity Summary for the Central Region, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

 15. Interstate Natural Gas Capacity Summary for the Midwest Region, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

 16. Interstate Natural Gas Capacity Summary for the Northeast Region, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

 17. Interstate Natural Gas Capacity Summary for the Southeast Region, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

 18. Interstate Natural Gas Capacity Summary for the Southwest Region, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

 19. Interstate Natural Gas Capacity Summary for the Western Region, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

 20. Relationship of Capacity and Utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

 21. Concentration of Reserved Firm Capacity by Region, April 1996 – April 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . 83

 22. Growth in the Capacity Release Market, November 1993 – March 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84

 23. Capacity Held by Replacement Shippers, by Region and Heating Years, 1994-95–1996-97 . . . . . . . . . . . . . . . . . 84

 24. Capacity Held by Replacement Shippers During the Nonheating and Heating Seasons, by Region . . . . . . . . . . . 86

 25. Natural Gas Pipeline Throughput Under Firm and Interruptible Service, January 1996 – September 1997 . . . . . 86

 26. Share of Total Firm Capacity Held on April 1, 1997, by Type of Shipper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

 27. Average Length of Long-Term Firm Contracts as of April 1, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

 28. Average Length of Short-Term Firm Contracts, January and April 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

 29. Average Firm Capacity per Contract as of April 1, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

 30. Share of Regional Firm Capacity as of April 1, 1997, by Shipper for Selected Regions . . . . . . . . . . . . . . . . . . . . 92

 31. Capacity Under New and Expiring Firm Contracts, April 1, 1996 – April 1, 1997 . . . . . . . . . . . . . . . . . . . . . . . . 93

 32. Reserved, Utilized, and Available Capacity for the 1996-97 Heating Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System vii

Executive Summary

Deliverability on the Interstate Natural Gas Pipeline System increase in pipeline capacity, would seem to indicate that

examines the capability 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, capacity was being added and that, in some areas,

highlighting the changes that have occurred since 1990. occasional bottlenecks or periodic capacity constraints

Significant changes have occurred in the natural gas industry might have occurred or were developing. In other areas,

since the Energy Information Administration (EIA) published the increase in pipeline usage rates simply reflected a

the predecessor to this report in 1992. Fundamental changes greater use of existing capacity that had been previously 1

in industry structure were imposed with the issuance of Order underutilized because of overbuilding or a temporary

636 in 1992 by the Federal Energy Regulatory Commission dropoff in demand.

that allowed market forces and competition to become the

primary factors influencing change in the natural gas  Reflecting its growing role in the U.S. natural gas

marketplace. Several new concepts in natural gas trading and market, Canadian import capacity into the United

distribution have developed, such as the market center, and States increased by 69 percent, or 4.5 billion cubic feet

changes have been made in how certain network resources are per day. It also represents the largest portion of new

being used in support of these system changes, such as open interregional pipeline capacity proposed for development

access to underground storage capacity. during the next several years. Although it is unlikely that

For the most part, these changes have been positive. Total import capacity expansion has been proposed, most of it

U.S. natural gas consumption has increased by 17 percent feeding into the U.S. Midwest and Northeast regions. To

since 1990, marketed production has increased by 6 percent, a great degree, the proposals are driven by producers in

net imports have nearly doubled, and the interstate pipeline Western Canada seeking markets for that region’s

system has increased in size and capability. Overall growth in expanding production capability. Plans to develop fields

the pipeline network has occurred in both its deliverability in the Sable Island area off the east coast of Canada have

and usage levels. For instance, between 1990 and the end of also triggered a need to find markets for that production

1996: as well. (Between 1990 and 1996, Canadian marketed

 Deliverability (capacity) on the interstate pipeline rate, while natural gas end-use consumption in Canada

system increased by more than 15 percent, or increased at only a 3.5-percent rate, thus the desire to

10.9 billion cubic feet per day, at regional borders expand export capabilities.)

(Table ES1). The largest increase in interregional 

deliverability was to the Western Region, with an Growth and changes in deliverability on the natural gas

additional 3.2 billion cubic feet (Bcf) per day, or network have also resulted in some shifts in transportation

45 percent (Figure ES1). The second largest increase was corridors and access to production areas. Deliverability out of

2.4 Bcf per day, 24 percent, into the Northeast Region. the Rocky Mountain area is increasing as producers there are

The development of so much capacity in the West led to seeking customers in expanding markets, such as the U.S.

a surplus of capacity and an overall drop in the pipeline Midwest, to supplement their traditional markets in the

capacity usage rate, whereas in the Northeast, demand Western Region. Likewise, producers and pipeline companies

growth fully supported the increase. In fact, pipelines in the areas of West Texas and New Mexico have also shifted

into the Northeast saw a substantial increase in average a larger portion of their capabilities toward Eastern markets.

daily usage rates, up 6 percentage points from 1990

levels. In 1997, at least 41 natural gas pipeline projects were

 Pipeline utilization rates also increased, by 6.3 Bcf per day of capacity overall, with 0.5 Bcf per day of

7 percentage points, reaching a high of 75 percent (on that representing added interregional deliverability and

an average day) in 1996. This increase in interregional 3.9 Bcf intraregional deliverability (Table ES1). A major

pipeline use, occurring simultaneously with a major portion of the new pipeline capacity represented increased

all projects will be built, more than 7.7 Bcf per day of

natural gas production increased at an 8-percent annual

completed and placed in service in the United States, adding

receipt capability in expanding supply regions. For instance,

the largest projects were in the Gulf of Mexico (3.2 Bcf per

day) as offshore and deep-water development efforts in the

area continue to expand. In addition, several major projects

were completed that expanded access to the Wind River and

Energy Information Administration, Capacity and Service on the 1

Interstate Natural Gas Pipeline System 1990: Regional Profiles and Analyses,

DOE/EIA-0556 (Washington, DC, June 1992).
Western

NN = 1996

(NN) = 1990

N% = Percent Change

 844

(354)

138%

Central

Southwest

Midwest

Southeast

Northeast

 350

(350)

0%

 45

(45)

0%

 298

(250)

19%

 3,786

(2,421)

45%

 20,846

(19,801)

5%

 8,609

(8,555)

1%

 5,351

(4,340)

23%

405

(405)

0%

 5,149

(4,971)

4%

 9,821

(9,645)

2%

 520

(100)

418%

 2,038

(2,024)

1%

 3,049

(2,161)

41%

 2,393

(467) 2,543 412%

(1,211)

110%

 4,887

(4,584)

7%

 2,354

(1,765)

33%

 9,879

(8,988)

9%

 1,194

(365)

227%

 1,563

(1,254)

25%

 2,114

(1,283)

64%

 66

(66)

0%

Energy Information Administration

viii Deliverability on the Interstate Natural Gas Pipeline System

Figure ES1. Region-to-Region Natural Gas Pipeline Capacity, 1990 and 1996

(Volumes in Million Cubic Feet per Day)

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity

Database, as of December 1997.

Table ES1. Regional Summary of Changes in Interstate Pipeline Capacity, 1990-1996, and Planned

Additions, 1997-2000

Entering the Region (MMcf/d) a Within the Region (MMcf/d) b

Region 1990 1996 1990-96 1997 1998-2000 2000 1990 1996 1990 1997 1998-2000 2000

Capacity Capacity Percent Capacity Additions Change Capacity Capacity Percent Capacity Additions Change

End of End of Change Added in to Capacity 1996- End of End of Change Added in to Capacity 1996-

Estimated Proposed Percent Estimated Proposed Percent

c

Central ........ 11,824 12,824 8 3 3,012 23 20,754 23,593 14 1,143 1,081 9

Midwest ........ 22,818 24,787 9 306 5,306 21 23,354 23,151 10 820 2,721 15

Northeast ...... 10,009 12,403 24 24 4,973 40 29,261 32,966 13 364 5,037 16

Southeast ...... 19,914 21,393 7 0 438 2 47,788 51,128 7 436 1,999 5

Southwest ...... 2,048 2,869 40 180 115 10 43,583 45,072 3 2,341 1,461 8

Western ....... 7,126 10,331 45 0 326 3 9,924 15,489 56 13 193 1

U.S. Total .... 73,739 84,606 15 513 14,170 17 174,664 191,399 10 3,874 12,492 9

Canada ........ 1,277 2,609 104 0 1,300 50 NA NA NA NA NA NA

Mexico . . . . . . . . 399 889 123 237 1,375 181 NA NA NA NA NA NA

Includes only the sum of capacity levels for the States and Canadian Provinces bounding the respective region. a

Represents the sum of the interstate pipeline capacity, or planned capacity, on a State-to-State basis as measured at individual State border b

crossing points, exclusive of capacities “Entering the Region.” Does not include projects that are entirely within one State. Gulf of Mexico projects

are considered within the Southwest or Southeast region.

Proposed capacity has been counted in only one region even though some projects may cross regional boundaries. In the case of a new line, c

the additional capacity has been included within the region in which it terminates. For an expansion project, the added capacity is included in the

region where most of the expansion effort is focused.

MMcf/d = Million cubic feet per day. NA = Not available.

D Sources: Capacity: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border

Capacity Database, as of December 1997. Capacity Additions: EIAGIS-NG Geographic Information System, Natural Gas Pipeline Construction

Database, as of March 1998, compiled from Federal Energy Regulatory Commission, Natural Gas Act Section 7(c) Filings, "Application for Certificate

of Public Convenience and Necessity," and various natural gas industry news sources.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System ix

Powder River basins of the Rocky Mountain area by almost from 10 percent. Practically all salt cavern storage sites

0.7 Bcf per day. The first new export lines to Mexico to be are accessible from market centers.

completed in 5 years were also placed in service during 1997.

The increase in pipeline utilization levels since 1990 can be  Availability of electronic trading. Another growing

attributed in part to new trading and shipping arrangements feature of the new natural gas marketplace is the

that evolved with the introduction of pipeline open-access increased use of computer-based electronic trading.

transportation and storage. The increased opportunities for Although there are only a few dominant systems in this

trading, variable routing of gas shipments, and the marketplace, the number of trades conducted via

development of new services to complement and expedite electronic trading has grown steadily during the past

network operations have done much to improve the efficiency several years. These systems bring together gas traders,

and utilization of available capacity. Several factors can be capacity seller/buyers, and others at a number of optional

cited as contributing to the improvement, including: points on the pipeline grid and assist the parties in

 Development of a release market for pipeline centers/hubs in North America, as well as a number of

capacity, whereby unused firm capacity can be sublet the most active spot-market trading points on the pipeline

by other shippers. The pipeline capacity release market grid, are accessible to traders. Not to be forgotten,

reached a level of about 3.6 trillion cubic feet in 1996 however, is trading on the non-electronic spot market,

(the equivalent of 16 percent of available capacity). which still accounts for the large majority of trading

Before FERC Order 636, there was only limited activity covering short-term buying and selling of natural

experience with capacity brokering, which had been gas. Currently there are more than 120 trading points

authorized by the Federal Energy Regulatory within the national pipeline network at which trading is

Commission in 1989. conducted by open-market traders.

 Development of market centers. Since 1990, when only In the market for pipeline capacity, shippers prefer long-term

one formal market center/hub was operational (the Henry contracts (a year or more in length) over short-term contracts

Hub in Louisiana), more than 36 market centers have and firm rather than interruptible transportation services.

developed at strategic points within the North American During the 12 months ended March 31, 1997, about

pipeline grid. These centers have contributed 78 percent of capacity was reserved under firm transportation

significantly to providing shippers greater access to contracts. However, not all of that capacity was used by the

lowest-cost gas supplies. Shippers now use market contract holders and, in addition, substantial firm

centers for rerouting gas supplies from one pipeline to transportation capacity is unsubscribed and available to

another and also for access to services, such as short-term shippers (27 trillion Btu per day, or 21 percent of maximum

gas loans and parking, that facilitate gas trading and capability in 1997). Although this uncommitted capacity may

improve pipeline capacity usage. The Henry Hub, the not suit the needs of a particular shipper because of its

Chicago Center (Illinois), and the Leidy Hub location or term etc., it could support additional market

(Pennsylvania) are the three most active market centers growth beyond current levels. Shippers also have access to

in the United States today. additional transportation services in which deliveries may not

 Improved access to underground storage. Open access services include capacity release and interruptible

to underground storage services, mandated in Order 636, transportation service and are available to shippers depending

has also played a large role in improving the quality of on the actual use of the pipeline system by firm transportation

transacting business on the natural gas pipeline network. customers. Marketers are the most active in the short-term and

The major trend in underground storage growth has capacity release markets because these markets provide the

been the increasing development of high-deliverability flexibility to meet varying and unexpected demand levels.

facilities, mostly salt cavern sites, which are designed to

permit rapid access and turnover of stored inventory.

These types of sites have become closely associated with

market centers as they complement the short-term

parking and loaning services offered by these centers.

Since 1993, daily deliverability from salt cavern and

other types of high-deliverability storage facilities has

grown to represent more than 15 percent of total

underground storage daily withdrawal capability, up

carrying out their transactions. Most of the major market

necessarily be guaranteed by the pipeline company. These

Outlook

Based upon EIA natural gas consumption projections, the

market for natural gas will continue to grow steadily into the

next century. EIA forecasts about a 2-percent annual growth

rate during the next 10 years (1999-2008). Excluding demand

in the supply areas, this translates into a projected increase in

consumption of nearly 1.2 trillion cubic feet by the year 2001.
Energy Information Administration

x Deliverability on the Interstate Natural Gas Pipeline System

In fact, the extensive number of currently planned capacity developing fields off the coast of Eastern Canada (Sable

additions and expansion projects indicates that substantial Island) to Canadian and U.S. markets. These expansions

activity is underway to address these potential increases in de- could add between 5.9 and 7.0 Bcf per day to U.S. import

mand. If all the projects currently proposed through 2000 capacity from Canada during the next 3 years along these

were built, interregional capacity would increase by as much corridors, an increase of more than 52 percent over 1997

as 14.7 billion cubic feet (Bcf) per day, or about 17 percent, levels.

from the level in 1996. Additional projects that are limited to

providing service within a specific region comprise an Current interregional and State-to-State capacity levels, in

additional 15.3 Bcf per day of capacity. most instances, appear to be adequate to meet current

Natural gas consumption is projected to grow at a 5-percent pipeline utilization rates increased significantly between 1990

annual rate in the Southeast Region through 2008, supported and 1996. This rise in usage is a strong indicator that

by anticipated growth in electric utility and industrial markets instances of peak-period capacity constraint could begin to

for natural gas. Markets in the Northeast and Midwest are occur if demand for natural gas in the affected markets were

projected to expand at annual rates of only 3.3 and to increase at a faster rate than expected. Also, while the

1.6 percent, respectively. Current proposals to expand amount of new capacity proposed for the next several years

pipeline capacity into these regions between 1998 and 2000 appears to be adequate, and in some instances more than

amount to the equivalent of about 10.7 Bcf per day, with adequate, to meet forecasted demand, there will probably be

5.3 Bcf per day directed to the Midwest, 5.0 Bcf to the some local areas with capacity constraints. 

Northeast, and 0.4 Bcf to the Southeast.

Based on current expansion proposals, the most extensive gas from supply areas to ultimate consumers has grown

development of new capacity during the next several years measurably since 1990, and the quality and flexibility of

will occur along the Canadian corridors. At least four new service has improved as well. Substantial further growth in

pipelines and several expansions are planned that will expand system capability is expected in light of the many expansion

deliverability from Canada to the U.S. Midwest and Northeast projects scheduled for completion during the next few years.

markets and also to Canadian domestic markets. These lines Further integration, improved services, and more interwill improve access to natural gas supplies in Western Canada connections along the grid should also help accommodate

and also create a new corridor to bring production from the anticipated future demand.

customer demands, although in a few instances average daily

The capability of the pipeline network to transport and deliver
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

1. Introduction

The United States has an extensive network of pipelines for  Analyze how regulatory change and market forces since

transporting natural gas from supply areas to all of the lower 1990 have created new market entities while altering the

48 States. In 1996, this system delivered about 20 trillion traditional role of a number of existing ones.

cubic feet of natural gas to end users, an average increase of

about 5 percent annually since 1990. This trend is expected  Characterize and compare the various production and 1

to continue, as Energy Information Administration (EIA) market areas in relationship to the interstate pipeline

projections indicate that demand could be near an all-time system.

high by the turn of the century. These projections of 2

increasing demand raise important issues for the U.S. pipeline  Assess shifts in market and end-use consumption patterns

transmission industry concerning the system's capability to within the different markets between 1990 and 1996.

move gas, the mechanisms for allocating capacity, and the

best way to apportion costs among users to obtain efficient  Identify and examine recent proposals for new pipeline

use of the system. routes and capacity expansions on existing lines,

Report Purpose and Structure

This report primarily examines the capability of the interstate

pipeline network to move natural gas to various markets

within the United States. The examination evaluates these

capabilities from supply areas to end-use markets, looking

first at the productive capacity and assets of major production

areas and the ability of the pipeline network to handle current

and proposed levels of production. It then assesses the ability

of the mainline pipeline network to transport and direct

supplies to end-use markets and the capabilities of the

trunklines and regional pipeline systems to deliver gas to the

ultimate consumer. Throughout the report, the data are

discussed and analyzed on a regional basis (see Figure ES1)

to reflect the significantly different profiles of various

production and market areas within North America that are

linked by the pipeline network.

The main purposes of this study are to:

 Quantify the capacity levels and usage of capacity on the

interstate pipeline network in 1996 between supply areas

and major market areas.

 Examine the changes that have occurred on the pipeline

network since 1990, including new pipeline systems and

expansions to existing systems.

3

particularly their effects on capacity levels.

The report does not attempt to identify specific instances of

excess pipeline capacity or system bottlenecks. Identification

of specific existing capacity constraints or excesses would

require modeling and simulation runs using actual daily

operational data. Such an endeavor would require more

detailed and specific data than were available for this study.

This chapter discusses some of the operational and regulatory

features of the U.S. interstate pipeline system: the shipper

requirements that affect the overall system design, the design

process, the system utilization, and the regulatory procedures

for capacity expansion. It also examines the differences

between various types of pipeline companies and the

importance of underground storage facilities in the design and

operation of a pipeline system.

Chapter 2 looks at how the exploration, development, and

production of natural gas within North America are linked to

the national pipeline grid. The analysis includes a profile of

current and, where possible, projected production levels

within the major natural gas-producing areas in the United

States and Canada. It also examines production levels relative

to pipeline capacity on pipeline systems exiting these areas

and entering the major natural gas transportation corridors

serving markets in North America.

The capability of the interstate natural gas pipeline network

to link production areas to market areas is examined in

Chapter 3, based on capacity and usage levels along

10 corridors. Each corridor is profiled and analyzed relative

'Excludes gas used for pipeline fuel as well as lease (field) and plant 1

processing. Also does not include Alaska and Hawaii. Energy Information

Administration, Natural Gas Annual 1996, DOE/EIA-0131(96) (Washington, Unless otherwise specified, historical or general production and

DC, September 1997), Table 1. consumption data cited throughout this report are based on the publication,

Energy Information Administration, Annual Energy Outlook 1996, Energy Information Administration, Natural Gas Annual 1996, DOE/EIA- 2

DOE/EIA-0383(96) (Washington, DC, January 1998). 0131(96) (Washington, DC, September 1997).

3
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System

to its combined pipeline capacity and usage levels, especially authorities. Some of these projects may not survive the

as to its receipt capability from supply areas and deliverability development process. Projections concerning production

to market areas. The chapter also examines capacity (Chapter 2) and future demand levels (Chapter 4), on the

expansions that have occurred since 1990 along each corridor other hand, reflect estimates presented in EIA’s Annual

and the potential impact of proposed new capacity. Energy Outlook 1998 With Projections to 2020 as produced

Chapter 4 discusses the last step in the transportation chain,

that is, deliverability to the ultimate end user. Flow patterns

into and out of each market region are discussed, as well as

the movement of natural gas between States in each region.

The profile of the customer base is addressed to provide some

insight into the current operation of pipeline and storage

facilities in the market area. The potential impact of

announced expansion projects is analyzed relative to current

capacity levels and the regional demand profile.

Chapter 5 examines how shippers reserve interstate pipeline

capacity in the current transportation marketplace. It looks at

how pipeline companies are handling the secondary market

for short-term unused capacity that is placed on the market by

shippers eager to lower their overall transportation costs. It

also analyzes the level of this (capacity release) trading and

what current trends might mean for firm and interruptible

contract (reservation) levels on pipelines in the future. The

report also includes four appendices that provide supporting

data and additional detail on the methodology used to

estimate capacity.

For the most part, the time series data used in this report cover

the years 1990 through 1996. There are a few exceptions

worth noting, however. Pipeline projects completed in 1997

are included in the analyses in chapters 3 and 4, although

these projects were only in service for a part of the year. Since

pipeline flow data for 1997 were not yet available, no attempt

was made to integrate the 1997 projects into any discussion of

pipeline utilization or specific State-to-State capacity profiles.

Another exception is the energy consumption data in

Chapter 4 (and Appendix C, Table C1). As of March 1998, no

comparative annual data for 1996 were available concerning

total national energy consumption by fuel type. While this

limited the data time series to the period 1990 through 1995,

the use of average annual (percent) change in the

accompanying profile analyses minimized the impact of the

1 year of missing data. It should also be noted that the

analysis in Chapter 5 examines firm transportation contract

data for the 1997 heating year (the 12 months ended

March 31, 1997).

Analyses concerning out-year projections vary with the types

of issues being addressed. Projections of pipeline capacity

additions through the year 2000 presented in the report are

based upon actual proposals currently under active

consideration by the pipeline companies and regulatory

from the EIA’s National Energy Modeling System (NEMS).

Defining Deliverability

“Deliverability” is defined for this report as the maximum

volume (capacity) that can be received, delivered, or passed

through a specific point during a specified period, e.g., 1 day.

Pipeline deliverability, or capacity, can be measured in

different ways, resulting in slightly different meanings. For

example:

 Systemwide peak-day capacity. Major interstate

pipeline companies file an annual capacity report

(18 CFR §284.12) with the Federal Energy Regulatory

Commission (FERC) that reports their daily system

capacity based on a design estimate of how much their

system can deliver for current shippers on a systemwide

peak day, otherwise known as the coincidental peak day

(Table 1). The derivation of this figure differs among 4

pipeline companies. Estimates of capacity on grid type

(regional) systems (see “Pipeline Utilization” section)

often are based upon the sum of system maximum

deliverability when the system is in a balanced state

(receipts match deliveries). Systemwide capacity on

trunkline systems usually represents the sum of capacity

at all delivery points.

 Peak-day capacity of each individual receipt, delivery,

or interconnection point. This estimate represents the

maximum amount of natural gas that can be delivered

into or out of the system during a period based on an

individual customer’s peak needs, although no system is

capable of reaching these maximums at all points on the

same day. The sum of these capabilities is known as the

“noncoincidental peak-day capacity.” It is called

noncoincidental because the days on which delivery

points on a pipeline system experience their peak flow

may not coincide.

 Capacity at a specific (strategic) point along the

pipeline system, usually at a compressor station or hub

interconnection (of several pipelines). Compressor

A coincidental peak flow is a volume measured at a delivery, receipt, or 4

interconnection point during a specified period (usually a day) when the entire

pipeline system operated at its maximum (throughput) for a given year. Thus

the day for this measure coincides for all shippers. 
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

Table 1. Forty Largest Interstate Pipeline Companies by Level of Deliverability, 1996

Company Name System Points Points (MMcf/d) (MMcf)

Type of Delivery Interconnect Capacity System Flow 1

Number of

Receipt

Points2

Number of Number of Peak-Day Peak-Day

2 3

Systemwide Coincidental

4 5

Columbia Gas Transmission Co. Grid 86 464 44 7,445 7,309

Transcontinental Gas Pipeline Co. Trunk 52 246 18 6,376 6,448

CNG Transmission Co. Grid 42 125 30 6,275 6,899

Tennessee Gas Pipeline Co. Trunk 701 386 112 5,981 6,887

ANR Pipeline Co. Trunk 92 355 35 5,923 6,311

Texas Eastern Transmission Corp. Trunk 158 178 62 5,761 5,414

Natural Gas Pipeline Co of America Trunk 203 322 43 5,208 5,957

El Paso Natural Gas Co. Trunk 54 618 8 4,744 4,075

Northern Natural Gas Co. Grid/Trunk 135 393 13 3,800 4,290

Koch Gateway Pipeline Co. Grid/Trunk 937 1,273 18 3,598 3,741

Northwest Pipeline Corp. Trunk/Grid 39 328 11 3,300 2,907

Texas Gas Transmission Corp. Trunk 197 377 49 2,950 3,621

Panhandle Eastern Pipeline Co. Trunk 7 117 7 2,917 2,744

Noram Gas Transmission Co. Trunk/Grid 736 754 33 2,811 2,335

Great Lakes Gas Transmission Co. Trunk 126 206 16 2,712 3,767

PG&E Gas Transmission Co. - Northwest Trunk 1 190 3 2,619 2,756

Transwestern Gas Pipeline Co. Trunk 80 40 10 2,615 1,292

Southern Natural Gas Co. (SONAT) Grid/Trunk 259 341 17 2,411 2,848

National Fuel Gas Supply Corp. Grid/Trunk 27 98 34 2,222 2,159

Columbia Gulf Transmission Co. Trunk 89 15 14 2,063 2,845

Colorado Interstate Gas Co Grid/Trunk 99 131 24 2,000 2,162

Northern Border Pipeline Co. Trunk 3 14 5 1,760 1,791

Trunkline Gas Co. Trunk 227 107 25 1,987 1,896

Williams Natural Gas Co. Grid/Trunk 298 897 31 1,820 --

Mississippi River Gas Transmission Co. Trunk 23 66 17 1,724 1,703

Algonquin Gas Transmission Co. Trunk/Grid 1 97 9 1,645 1,513

Florida Gas Transmission Co. Trunk 62 209 19 1,497 1,611

Questar Pipeline Co. Grid/Trunk 136 15 13 1,380 1,167

Sabine Gas Pipeline Co. Trunk 10 15 11 1,304 1,211

Equitrans Inc. Grid 2 132 10 843 737

Iroquois Gas Pipeline Co. Trunk 11 10 4 826 1,017

Midwestern Gas Transmission Co. Trunk 4 21 7 785 935

Kern River Gas Transmission Co. Trunk 5 39 3 714 848

East Tennessee Natural Gas Co. Grid/Trunk 0 147 6 634 726

KN Interstate Gas Co. Grid/Trunk 67 388 19 575 508

Wyoming Interstate Gas Co. Trunk 0 0 4 500 579

Viking Gas Transmission Co. 1 42 4 490 517 Trunk

Williston Basin Interstate Pipeline Co. Grid/Trunk 62 271 4 458 490

Trailblazer Pipeline Co. Trunk 1 3 4 422 588

Mojave Pipeline Co. Trunk 0 17 2 407 577

Total 103,502

"Trunk” systems are long-distance trunklines that generally tie supply areas to market areas. “Grid” systems are usually a network of many 1

interconnection and delivery points that operate in and serve major market areas. Some systems are a combination of the two. Where two are

shown, the first represents the predominant system design.

Pipelines with zero receipt and/or delivery points transfer volume via interconnections with other interstate pipelines. 2

Represents a receipt, delivery, or emergency interconnect with one or more of the other pipeline companies listed in this table. 3

Some pipeline companies reported their system levels in decaterms per day (Dth/d) rather than in million cubic feet per day (MMcf/d). In those 4

instances, a factor of 1.027 was used for the conversion.

Total volume reported as delivered off the entire pipeline system on its peak-day during the heating year extending from April 1, 1996, through 5

March 31, 1997. All volumes reported in Dth/d and converted to MMcf/d using a 1.027 conversion factor.

MMcf/d = Million cubic feet per day.

Source: Federal Energy Regulatory Commission (FERC). Receipt/Delivery/Interconnects: FERC 567 Capacity Report, “System Flow

Diagram.” Systemwide Peak-Day Capacity: FERC Annual Capacity Report (18 CFR §284.12). Peak-Day Flow: FERC Form 2, “Annual Report

of Major Natural Gas Companies.”
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

stations can be viewed as choke points along a system be expressed as a reservation on system capacity for the

because they are designed to move a limited amount of receipt and delivery of a maximum daily quantity of gas at

gas through their location over a period of time. Capacity specific points along the network. Under firm transportation

measures for individual pipelines at a hub are dependent contracts, the pipeline company agrees to reserve capacity on

upon the capabilities of the hub itself and operational its system to provide a shipper, such as a local distribution

aspects of other pipelines using the hub during a peak company (LDC), industrial user, or electric utility, with up to

period. a specified quantity on any given day. Pipeline companies

This report primarily uses the “specific point” measure of specified under firm contracts even though their shippers may

deliverability, based on an estimated design throughput not need or actually request transport of that gas. (However,

capability of a pipeline as it crosses State borders. This design in certain instances, pipeline companies have the authority to

capacity estimates the flow that could be obtained along a impose restrictions on the level of service they are obligated

pipeline segment on a sustained basis under a specific set of to provide (see Box, “Operational Flow Orders”)).

conditions and thus provides a measure of comparability

across all pipeline systems. LDCs are still the principal providers of supply to the ultimate

It should be emphasized that the capacity numbers derived for sold to end users in 1996 (down from 46 percent in 1993) and

this report are merely “reasonable” estimates based upon 25 percent of the gas transported on their behalf (up from

design or contractual conditions. Actual capacity at a 20 percent in 1993). They typically contract with pipeline

particular point or system wide is rarely one stable figure. companies for firm transportation and storage services to meet

Weather conditions, ambient temperature, elevation, and the requirements of their high-priority customers and for

operational variables, such as short-term line packing and interruptible service to meet the needs of their lower priority 5

line pressure shifts, can affect stated capacity levels. In some customers. However, in some States where open-access

cases, line packing can increase operational capacity by as transportation and deregulation are being tested, LDCs are

much as 20 to 30 percent. Some of this increase is reflected in slowly becoming merely deliverers for other sellers. In 1996,

the differences between system capacity and peak-day flows nonsales deliveries represented 37 percent (4.9 trillion cubic

shown in Table 1. In a number of cases, the peak-day flow is feet) of total LDC deliveries, up from 30 percent in 1993.

well above the reported overall system capacity. 

The pipeline capacity estimates in this report are based residential, (2) commercial, (3) industrial, and (4) electric

primarily upon compressor station data in the Federal Energy utility. Residential and commercial gas consumers usually

Regulatory Commission Format 567, “System Flow have no other alternative for fuel except through the LDCs

Diagrams,” filed annually by the major interstate pipeline and thus are considered high-priority users. In contrast, many

companies. (See Appendix C for a detailed discussion of how industrial users and electric utilities do not require firm

capacity levels were derived and refined.) Systemwide service because they often have the capability to switch to

capacity levels, when used, are based upon data reported to other fuels. Some electric utility and industrial consumers

FERC by the major interstate pipeline companies in their contract for service on an interruptible basis. Under

annual capacity reports that accompany Format 567 (18 CFR interruptible contracts, deliveries are subject to curtailments

§284.12) or constructed from pipeline delivery data reported by the pipeline company or local distribution company when

on FERC Form 11, “Natural Gas Pipeline Company Monthly necessary to meet the requirements for service under firm

Statement.” contracts. Rates for interruptible service are generally less 6

Shipper Requirements

Ultimately, the shippers’ requirements determine the design

capacity of pipeline system facilities. Pipeline companies seek

to obtain a mix of shippers and contract types in order to

maximize system throughput. Firm service requirements may

must stand ready to provide service up to the volume level

end user, accounting for about 42 percent of the natural gas

Consumers are generally classified into four categories: (1)

expensive than for firm service. Service to interruptible

shippers is extremely important to the pipeline companies in

their efforts to maintain a high level of throughput.

The demand for natural gas is quite diverse regionally. For

example, in the northern regions of the country where a high

proportion of residential and commercial consumers use

natural gas for heating, deliveries under firm service contracts

are highly seasonal because of the extreme weather variation.

Other more temperate regions, such as the Southwest, may be

very dependent on natural gas used in the generation of

electricity to meet summer cooling loads. The use of natural

gas for industrial purposes also varies substantially from

Line packing is temporary storage of pipeline gas through the use of 5

increased compression.

The FERC Form 11 data used are only through 1995. The form was 6

revised in 1996 and now is filed only on a quarterly basis.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

Operational Flow Orders

When FERC Order 636 was instituted in 1993 and open access became the norm, the Federal Energy Regulatory Commission

recognized that pipeline operators needed a mechanism in place 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 such as extreme

weather, unscheduled downtime on critical parts of the system, and extreme imbalance situations are some of the reasons

pipeline companies cite as the need for such short-term control. 

Operational flow orders (OFOs) (also called system emergency orders or critical period measures) are the mechanisms put

in place to permit this control. In effect, these orders permit the pipeline operator during emergency situations to restrain

shipper activities and to curtail services that could result in imbalances and service interruptions. For instance, OFOs allow

the operator to reduce or eliminate flow tolerances and require shippers to maintain a strict daily balance between receipt and

delivery volumes. The OFO also may restrict or eliminate such services as intraday nominations, the use of secondary receipt

and delivery points, firm storage withdrawals, and interruptible storage services. As an enforcement measure, pipeline

companies can exact penalties for violations (pipeline companies do not bear any costs incurred as a result of service

restrictions and they get to keep any penalty revenues).

Despite their utility, OFOs are controversial. The direct consequence of measures taken under OFOs is to lessen short-term

trading and shipping flexibility on the part of customers. Some maintain that pipeline operators are given too much discretion

regarding what constitutes an OFO situation and that operators have incentives for maintaining the OFO for longer than is

needed. Critics also argue that the fact that the pipeline company can retain any penalty revenues and place restrictions on

nonfirm services and secondary receipt/delivery points is a disincentive to shippers who want these lower-cost services but

are unwilling to risk possible interruption of their operational flows during peak periods. 

While operating contingencies must be addressed and some form of pipeline system control during stress periods and

emergencies will continue to be required, the criteria for OFO implementation may be changed as more experience is gained

with emergency situations under open-access conditions. For instance, it has been suggested that the restrictions be imposed

in a ratcheted manner, implementing more severe restrictions only if the lesser ones fail to alleviate the situation. Among the

other possibilities: limit restrictions only to those parts of the system that are under stress; give shippers more advance notice

before issuing the OFO; remove any financial incentives to pipeline companies under the OFO; and clearly define within the

pipeline company’s tariff the conditions for imposing an OFO and what operational conditions constitute an end to an OFO.

region to region. Some applications use natural gas for The design of the transmission lines and integrated storage

feedstocks and require a secure, dedicated supply of natural sites represents a balance of the most efficient and economical

gas. Other uses are for boiler fuel where the user typically has mix of delivery techniques given the operational requirements

the capability to burn other fuels in the event that natural gas facing pipeline companies. The mix varies widely depending

is not available or is less economic than the alternatives. on the number and types of shippers and access to supplies,

Transmission System Design

The principal requirement of the natural gas transmission

system is that it be capable of meeting the peak-day demand

of its shippers who have contracts for firm service. To meet

this requirement, the principal facilities developed by the

natural gas industry are a combination of transmission lines

to bring the gas to the market areas and of underground

storage and liquefied natural gas (LNG) facilities closer to the

market areas to meet surges in demand (Figure 1).

either from production areas or underground storage. Many

pipeline systems are configured principally for the longdistance transmission of supplies from production regions to

market areas and are characterized as “trunklines” (Table 1).

At the other extreme are the “grid” systems, which generally

operate in and serve major market areas. Many of the grid

systems can be categorized as regional distribution systems.

For the most part, they receive their supplies from major

trunklines or directly from local production areas and

transport gas to local distribution companies and other

consumers in more than one State.

Underground storage is an essential component of an efficient

and reliable interstate natural gas transmission and
Baseload

Production

Underground 

Storage

Ultim ate

Consumer

Processing Plant

(Extraction)

Peak

Periods 

Offpeak

Periods

M arket Area Storage

LNG (peaking) 

(Excess) Storage

Dry Gas

Liquids

Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

Figure 1. Generalized Schematic of Natural Gas Pipeline Transmission

Note: Areas shown are not proportional to actual operational volumes or capacity.

Source: Energy Information Administration, Office of Oil and Gas.

distribution network. The size of the transmission line often where there is a strong seasonal variation to demand and

depends in large part on the availability of storage. Rather where the system may be subjected to some operational

than size a line to meet peak-day volumes, the line need imbalances. 

satisfy only the difference between total shipper peak

requirements and maximum withdrawal from storage as it The daily deliverability from storage can also be factored into

enters the market area. In off-peak periods, the line must be the design needs of a new pipeline or the expansion needs of

able to provide shippers’ off-peak needs plus injection to an existing one. Some underground storage facilities are

storage. In addition, some storage sites may require that located in production areas at the terminus of the pipeline

system flow be reversible and that the main transmission line corridor and, in contrast to storage near local markets, can be

in the vicinity be able to accommodate this capability. The used to store gas that may not be economically marketable at

resulting pipeline configuration, including storage, may result the time of production. These sites can be used by shippers

in a comparatively low usage level in the off-peak season and to store short-term excess supplies that exceed their reserve

a much higher, albeit shorter term, usage level during the capacity on the pipeline system and the reverse when supplies

peak-demand season. fall below reserved capacity. Thus, the pipeline is relieved of

During the nonheating season, for instance, when shippers do swings in transportation demands.

not use all the capacity contracted for, natural gas can be

transported and injected into storage at a fairly constant rate. Often new systems are initially designed to handle volumes

By the beginning of the heating season (November 1), beyond the minimum requirement. A number of factors are

inventory levels are generally at their annual peak. Working involved in calculating how much gas a pipeline can carry,

gas, that is, the portion of natural gas in storage sites the most important being the diameter of the pipe and the

ordinarily available for withdrawal and delivery to markets, pressure pushing the gas along the pipe. Because of flow 7

is then withdrawn during periods of peak demand. dynamics, doubling the diameter of the pipe will increase the

In addition, the pipeline company itself can avoid the need to

expand transmission capacity from production areas by using

existing, or establishing new, storage facilities in market areas

8

additional demands for capacity brought on by temporary

9

In addition to working (top storage) gas, underground storage reservoirs can be injected during the off-peak season and delivered, at high pressure, to 7

also contain base (cushion) gas and, in the case of depleted oil and/or gas field the mainline during the peak season.

reservoirs, native gas. Native gas is gas that remains after economic Standard design codes require that all pipelines passing though populated

production ceases and before conversion to use as a storage site. Native gas areas have their maximum operating pressures reduced for safety reasons. It

and base gas typically are not withdrawn from the storage facility, as these became common practice to maintain nominal diameter but increase wall

volumes are necessary to ensure sufficient pressure for the withdrawal of the thickness where a line had to be derated for its surroundings in order to keep

working gas. the working pressure rating more constant along the line.

For instance, natural gas produced in association with oil production is a 8

function of oil market decisions, which may not coincide with natural gas

demand or available pipeline capacity to transport the gas to end-use markets.

Another example is the storage of gas from low-pressure wells, where the gas

9
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

capacity more than sixfold at approximately twice the cost. potential for obtaining a high utilization rate because the load

Increasing the pipe wall thickness or strength of the pipe will moving on these pipelines can be levelized. Furthermore, to

enable the pipe to withstand a greater pressure. The pressure the extent these pipelines serve multiple markets, they can

pushing the gas is usually provided by mechanical also achieve higher utilization rates because of load diversity

compression. across the markets they serve.

The design process itself includes the development of cost In fact, some trunkline systems, especially those reaching

estimates for various possible combinations of pipe size, high-demand markets, often exhibit peak daily utilization

compression equipment, and interstation distances to find the rates greater than 100 percent. For example, the Iroquois

combination that minimizes transportation cost given the Pipeline system, which transports Canadian gas to the U.S.

desired flexibility and expandability goals. New trunklines are Northeast, showed a peak-period usage rate above

typically built with larger diameter pipe than needed initially, 100 percent in 1996, as did the Trailblazer Pipeline system

but only with the currently required compression capacity. out of the Rocky Mountains area. Several factors contribute

Compression can then be added, either in existing or new, to this situation. First, some trunkline systems are capable of

intermediate stations, to increase capacity as growth in load handling much larger volumes than indicated by the

occurs. operational design level certificated by FERC, which is the

Pipeline Utilization

Pipeline companies prefer to operate as close to capacity as

possible, thus maximizing revenue; however, the average

annual utilization rate usually does not reach 100 percent even

in cases of full utilization. Several factors contribute to these

lower rates, including the outages resulting from pipeline

maintenance. During the summer months, when pipeline

capacity demands are lowest, most pipeline companies

schedule needed maintenance. As a result, some pipeline

segments or compressor facilities may be placed out of

service and transportation service suspended temporarily, for

a day, a week, or even as long as a month.

Thus, average utilization rates below 100 percent do not

necessarily imply that additional capacity is available. A

pipeline company that serves primarily a seasonal market may

have a relatively low average utilization rate even if there is

no unreserved capacity on its system. Yet because of the

difficulty in balancing unused commitments for firm service

with interruptible service and transportation for others, it may

be unable to provide further interruptible service to

complement the high level of deliveries required during the

peak consumption periods.

Integration of storage capacity into the pipeline network

design can increase average-day utilization rates. Storage used

for seasonal demand-swings effectively moves demand from

one season of the year to another. Trunklines, which are

generally upstream of the market storage areas, can be

designed for a more constant load than the pipelines on the

downstream side of the storage fields. Storage is usually

integrated into or available to the system at the production

and/or the market end as a means of balancing flow levels

throughout the year. Therefore, trunklines serving markets

with significant storage capacity have a much greater

10

level that is used as the denominator when calculating usage

rates (based on an annual throughput volume divided by

365 days). Second, as the line can handle more than the

certificated capacity and shipper demand is high, maximum

usage is made of the pipeline by its owners. In many instances

of high demand, pipeline companies also use line packing

and/or secondary compression to increase throughput, which

was a tactic used by both Iroquois and Trailblazer this past

year. When average daily utilization rates exceed stated

capacity, it is more appropriate to use the peak-day volume as

the actual capacity, or capability, of the system. 

Utilization on the grid systems operating closer to the market

areas and downstream of the storage fields is more likely to

reflect 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 much higher rates. Grid systems usually

show a marked variation between high and low flow levels,

reflecting their seasonal service and local market

characteristics. Storage services are usually highly integrated

into the grid network to meet varying local market demands.

Because grid systems have numerous interconnections 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 instances the sum of individual 10

transportation transactions may exceed pipeline capacity even though

physically 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 capacity of 200

million cubic feet (MMcf) per day. Suppose further that this segment handles

a 100 MMcf per day transaction from A to B, a second of 100 MMcf per day

from B to C, and a third of 100 MMcf per day from C to D. The pipeline

company will report transportation volumes of 300 MMcf per day, even

though its capacity is 200 MMcf per day but is only 50 percent utilized on any

one segment.
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

shipper (or group of shippers) with relatively constant review of the environmental aspects of the projects. These

demand or have a significant interruptible service market. requirements have resulted in a very time-consuming,

The primary measure of pipeline utilization used in this

analysis is an estimate of average-day natural gas throughput Once a project is approved and constructed under a Section

relative to estimates of system capacity at State and regional 7(c) certificate, the costs of the facilities are eligible for

boundaries. Another measure used is systemwide pipeline inclusion in the pipeline company rate base (when the

flow rates, which highlight variations in monthly system company files its next general rate case). Other options are

usage relative to an estimated system peak throughput level also available to pipeline companies for capacity expansion,

(see Box, “Pipeline Utilization Measures”). In some instances, depending on the size of the project and the amount of risk

where data were available, pipeline peak-day utilization rates the company is willing to assume. These options include:

are referenced in this report. System peak-day usage rates,

although only a reflection of peak system deliveries versus  Blanket Certificate. Blanket certification can be used for

estimated system capacity, come the closest to showing how relatively small projects. A blanket certificate approves a

well the design of the system matches current shipper peak- series of similar actions in one authorization. For

day needs. For example, when a pipeline shows a compara- instance, construction of small additions to a pipeline may

tively low average usage rate (based on annual or monthly be authorized by a blanket certificate, provided the total

data) yet shows a usage rate approaching 100 percent on its cost does not exceed some threshold level and other

peak day, it indicates that the system is still called upon and eligibility criteria are met. Similarly, pipeline companies

is capable 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 can indicate a need to find better ways shippers on the approval of a single blanket certificate. In

to utilize off-peak unused capacity. recent years, FERC has been using blanket certification

Capacity Expansion

Although pipeline systems have some flexibility in handling

changes 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 continues today. Two

of the largest proposals of the late 1980's to be implemented

during the early 1990's were the Iroquois project, built to

bring Canadian natural gas into the Northeast, and the Kern

River project, which now transports natural gas from supply

sources in Wyoming to California. These new lines began

service in 1991 and 1992, respectively. A large number of

other new systems and expansions are planned or under

construction that will bring additional supplies from Canada,

as well as from the Rocky Mountains area and the Southwest,

to the U.S. Midwest and Northeast regions.

In most cases, interstate pipeline companies are required

under Section 7(c) of the Natural Gas Act of 1938 to obtain

a certificate of public convenience and necessity before

constructing pipeline facilities. Besides review of operational

aspects of the system, other legislation requires extensive

11

complex, and sometimes controversial process.

12

more frequently to authorize and facilitate both

construction projects and transportation programs.

 Optional Certificate (formerly known as Optional

Expedited Certificate). In 1985, under Order 436, FERC

introduced optional certificates whereby construction

could be approved without assessment of its market need

or competitive proposals. In return, the pipeline company

agrees to bear the majority of the risk of the project.

Furthermore, the pipeline company may not decrease the

projected volume of services used to design rates nor

shift costs to pre-existing shippers. Because of the “at

risk” factor, some optional certificate projects tend to be

more adversely affected by procedural delays since

changes in market conditions that occur in the meantime

may necessitate a re-evaluation of the project’s feasibility

and its potential success.

 NGPA Section 311. Section 311 of the Natural Gas

Policy Act (NGPA) of 1978 allows an interstate pipeline

company to sell or transport gas “on behalf of” any

These laws include: the National Environmental Policy Act, National 11

Historical Preservation Act, Endangered Species Act, Toxic Substances

Control Act, Clean Air Act, Clean Water Act, Coastal Zone Management Act,

Wild and Scenic Rivers Act, Wilderness Act, and National Parks and

Recreation Act.

In some instances, FERC may also issue a Section 7(c) certificate subject 12

to “at risk” conditions. In such cases, the pipeline companies are not

guaranteed authority to include costs in the rate base, and risks borne by the

companies are not reduced. Under an “at risk” certificate, a pipeline company's

risk is minimized only where it has fully contracted the capacity of a new line.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 	

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 capacity at State boundaries. Average-day throughputs were computed by dividing annual Stateto-State flows in 1990 (reported by pipeline companies) 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 capacity level. This measure provided

the basis for the analysis pertaining to usage of specific portions of a pipeline system and additionally some insight into the

type of service provided in the area.

But, because it uses averaged annual throughput volumes, the measure implies nothing about the availability of capacity during

peak periods, except to the extent that the average daily utilization approaches, or exceeds, 100 percent. (Service levels on

a pipeline system often vary from month to month, day to day, and even hourly.) As the computed utilization rate approaches

100 percent, it indicates only that the volume of gas moving through a specific geographic area on an average day during the

year approximated estimated capacity. When this does occur, however, it is likely that the specific system location experiences

some constraints during peak periods. A system that fully utilizes available capacity 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 computed. These rates are based on a comparison of 1995 monthly throughput (the latest available monthly

data) on the entire pipeline system with the largest throughput (sales, transportation, and intercompany transfers) that occurred

in any month over a 15-year period (1980-1995). They were developed to show the degree of difference that occurs on

different types of systems over the year as seasons and demand change. In these computations, the highest monthly throughput

during the 15-year period is used as the proxy for the systemwide capacity of the pipeline. (This method has its limitations,

including the fact that accounting of throughput can vary by pipeline company, leading to the reporting of excess throughput

levels.) For 1995, (1) average-month throughput, (2) high-month throughput, and (3) low-month throughput were each divided

by the 15-year high-month throughput to derive three flow-rate percentages. 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 computed. (April and October are considered to be months that “shoulder” the heating season of November through

March.)

Another systemwide usage rate was also computed based upon an annual system (deliverability) capacity level reported to

the Federal Energy Regulatory Commission (FERC) by the major pipeline companies and the system’s yearly peak 1-day

volume. This figure provided a snapshot of the system’s maximum use level containing a minimum skew caused by downtime

and other factors.

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 instance, systems with a

high-month rate of 100 percent in 1995 had a record monthly throughput level in 1995. If these same systems also exhibited

high average utilization rates at State border crossings, they may be constrained in their abilities to serve additional shippers

without capacity expansion. In contrast, systems having a relatively low peak-month throughput but high average utilization

levels at specific points along the network probably are experiencing more localized capacity constraints.

Comparison of the systemwide average-month flow rates with utilization rates at State border crossings can 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 crossings but the systemwide average-month rate is significantly lower, then there are likely to be elements

of the system, probably wholly contained 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 significantly 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

interconnect and transfer large volumes of gas from one system to another. 
Energy Information Administration


 Deliverability on the Interstate Natural Gas Pipeline System

intrastate pipeline or local distribution company. FERC new pipeline projects at various stages of development in the

has exempted the construction of facilities used solely for United States, Canada, and Mexico. If all U.S. projects were

Section 311 transportation from certificate requirements. completed, the amount of new capacity would add more than

Construction is subject to environmental conditions and 29 billion cubic feet of daily deliverability on the national

a 30-day notice to FERC, which requires only network. The most extensive development is focused on

information on the delivery point of gas from the expanding the deliverability of Canadian gas to the U.S.

interstate pipeline, the total and daily volumes expected Midwest and Northeast and to Canadian markets. The secondto be delivered, and the rate to be charged for largest focus is on improving access to the increasing deeptransportation or sale. water production in the Gulf of Mexico. Next are those

Planned expansions of the current pipeline system are cost supplies located in the Central United States to markets

proposed under each of these options and are detailed in located primarily in the Midwest. Currently, the capability to

Appendix B. The traditional Section 7(c) application is still do so is limited. The latter series of expansions will be

the most widely used. competing, to some degree, with the projects slated to

As of March 1998, the Energy Information Administration marketplace. The potential impact of proposed capacity

was tracking more than 100 proposed pipeline expansions and expansions is discussed in subsequent chapters.

projects whose objective it is to increase the flow of lowerincrease flows of Western Canadian gas to the Midwest
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

2. Access to Supplies and Production Areas

Natural gas production patterns in the lower 48 States have 1990s, growing as a major source of deliverability in the

changed in recent years as new fields have been brought on lower 48 States.

line and older gas-producing areas have declined in

importance. For example, the eighth largest gas field in the Alaska is not included as a supply area in this study because

United States in 1996 in terms of output, Bob West in its natural gas production is not destined for U.S. markets in

southern Texas, was discovered only in 1990 and as late as the lower 48 for some time to come and therefore does not

1993 did not even figure among the top 30 producers. Also, directly affect U.S. gas deliverability within the time frame of

new technology has rejuvenated older fields and allowed the analysis.

production from fields previously thought uneconomic.

The shifts in regional production will affect existing pipeline

routes, reducing flows along some, while increasing flows

along others. Some regional production increases from new

gas fields in the Rocky Mountain area and New Mexico will

require additional capacity to transport the gas to markets.

The Gulf Coast region has seen a substantial increase in

production over the past several years and, although

traditionally served by an extensive pipeline network, will

probably require the addition of new capacity. Meanwhile,

production in the Anadarko and Arkoma Basins declined

during the first half of the 1990s.

This chapter discusses U.S. natural gas deliverability at the

wellhead through 2000 and the capability of the pipeline

network to receive and export that gas through the national

network grid. The analysis focuses on eight producing areas

that roughly correspond to major geologic basins in the lower

48 States (Figure 2), as well as imports from Canada.

Relatively new producing regions (in terms of average field

age) covered in this chapter include the offshore Gulf of

Mexico; major fields in the Rocky Mountain States of Utah,

Colorado, and Wyoming; and the San Juan Basin of New

Mexico. Older producing regions examined include 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

Appalachian Basin. Although a relatively minor gas 13

producer, the Appalachian Basin region is notable because of

its proximity to major markets in the Northeast. Canada has

sharply increased gas exports to the United States during the

U.S. Natural Gas Supplies by

Region, 1990-2000

Total natural gas production in the lower 48 States has shown

an upward trend during the 1990s, rising 5 percent from an

average 47.7 billion cubic feet (Bcf) per day (17.4 trillion

cubic feet (Tcf) on an annual basis) in 1990 to 50.1 Bcf per

day (18.4 Tcf per year) in 1996 (Table 2), its highest level

since the early 1980s. Higher gas demand and stable prices

are projected to raise production in the lower 48 to about

54 Bcf per day (19.8 Tcf per year) in 2000. The 1.9-percent

average annual growth rate forecast for the period 1996

through 2000 is more than double the production growth rates

of the first half of the 1990s.14

Lower 48 gas reserves increased to 156 Tcf in 1996, marking

the third consecutive year of higher reserve levels although

still slightly below the 1990 level of 160 Tcf. This recent

trend is expected to continue. Various factors, such as

improved well completions, advanced stimulation technology,

and improved seismic technology, have allowed producers to

maximize gas output from existing fields, resulting in a

decline in the ratio of reserves to production since 1990. The

near-term supply outlook for natural gas shows expanded

production through 2000, reflecting the recent production

trends as well as the substantial volume of remaining

resources. One recent study estimated remaining recoverable 15

gas resources at 929 Tcf as of December 31, 1996, suggesting

The regional data were aggregated from data by State and sub-State estimates, based on relative dry gas production values as reported in the EIA 13

areas. The lack of strict correspondence 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 excluded, or other lesser basins may be DOE/EIA-0216(96) (Washington, DC, December 1997), and earlier editions.

included in the regional estimates. For expository purposes, the regions, in Energy Information Administration, Annual Energy Outlook 1998,

some cases, are treated as equivalent to the major basins within the regions. (Washington, DC, December 1997).

Unless otherwise noted, all forecasts are derived from data in the Energy 14

Information Administration (EIA) publication Annual Energy Outlook 1998

With Projections to 2020, DOE/EIA-0383(98) (Washington, DC, December

1997). Historical 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

15
Sacramento

 Basin

San Joaquin

 Basin

San Juan

 Basin

Uinta/Piceance

 Basin

 Western Canada

Sedimentary Basin

Williston

 Basin

Green River

 Basin

Permian

 Basin

Powder River

 Basin DenverJulesberg

 Basin

Anadarko/

 Arkoma

Illinois Basin

South Texas

 Basin 

Gulf Coast Basin

 East Texas/

North Louisiana

 Basins

Black Warrior

 Basin 

Appalachian Basin

Michigan

 Basin

3,000

6,000

9,000

12,000

15,000

 0

 Capacity

(Million Cubic Feet per Day)

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System

Figure 2. Major Natural Gas Producing Basins and Transportation Routes to Market Areas

Correspondence to Major Natural Gas Producing Regions

Producing Region State or Substate Regions Basins Contained Whole or in Part

Gulf Coast South Louisiana (onshore) Gulf Coast and South Texas Basins

Texas RRC Districts 1, 2, 3, 4

Anadarko/Arkoma Arkansas Anadarko/Arkoma Basin

Kansas

Oklahoma

Texas RRC District 10

Permian Basin New Mexico, East Permian Basin

Texas RRC Districts 7B, 7C, 8, 8A, 9

Rockies Colorado Uinta/Piceance, Julesberg, Powder River, and

Utah Green River Basins

Wyoming

East Texas North Louisiana East Texas/North Louisiana Basins

Texas RRC Districts 5, 6 

San Juan Basin New Mexico, West San Juan Basin

Appalachian New York Appalachian Basin

Ohio

Pennsylvania

Virginia

West Virginia

Other Onshore Alabama, California (onshore), Florida, Kentucky, Michigan, Williston, Sacramento, San Joaquin, Illinois,

Mississippi, Arizona, Illinois, Indiana, Maryland, Missouri, Michigan, and Black Warrior Basins

Montana, Nebraska, Nevada, North Dakota, Oregon, South

Dakota, and Tennessee

Offshore Federal waters of the Gulf of Mexico, and State waters of

California, Alabama, Louisiana, and Texas

Source: Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity Database,

as of December 1997.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

Table 2. Natural Gas Production and Supplies in the Lower 48 States, by Region, 1990-2000

Annual Gas Supplies Daily Gas Supplies Change in Gas Supplies Share of Total Supplies

(billion cubic feet per year) (billion cubic feet per day) (percent increase/decrease) (percent)

Region 1990 1996 (forecast) 1990 1996 (forecast) 1990-96 (forecast) 1990 1996 (forecast)

2000 2000 1996-2000 2000

Lower 48 Production

Gulf Coast 3,130 3,340 3,432 8.6 9.1 9.4 6.4 2.8 16.5 15.7 14.4

Anadarko/Arkoma 3,339 2,929 2,967 9.1 8.0 8.1 -12.5 1.3 17.6 13.8 12.4

Permian Basin 1,663 1,621 1,890 4.6 4.4 5.2 -2.8 16.6 8.8 7.6 7.9

Rockies 911 1,497 1,668 2.5 4.1 4.6 63.9 11.5 4.8 7.0 7.0

East Texas 1,109 1,153 1,185 3.0 3.2 3.2 3.7 2.8 5.8 5.4 5.0

San Juan Basin 511 988 1,101 1.4 2.7 3.0 92.9 11.5 2.7 4.6 4.6

Appalachian Basin 496 504 583 1.4 1.4 1.6 1.3 15.7 2.6 2.4 2.4

Other Onshore 844 828 1,073 2.3 2.3 2.9 -2.2 29.6 4.5 3.9 4.5

Total Onshore 12,003 12,859 13,899 32.9 35.1 38.0 6.8 8.1 63.3 60.4 58.2

Offshore 5,425 5,491 5,881 14.9 15.0 16.1 0.9 7.1 28.6 25.8 24.6

Total Lower 48 17,428 18,350 19,780 47.7 50.1 54.0 5.0 7.8 91.9 86.2 82.8

Lower 48 Imports

From Canada 1,448 2,883 3,910 4.0 7.9 10.7 98.6 35.6 7.6 13.5 16.4

Total Lower 48 1,532 2,937 4,120 4.2 8.0 11.3 91.2 40.3 8.1 13.8 17.2

Total Lower 48

Supplies 18,960 21,287 23,900 51.9 58.2 65.3 12.0 12.3 100.0 100.0 100.0

Sources: 1990-96 Data: Energy Information Administration (EIA), Natural Gas Annual 1996 (September 1997) and earlier editions. Production

volumes by regions were derived based on relative dry gas production values published in U.S. Crude Oil, Natural Gas, and Natural Gas Liquids

Reserves 1996 (December 1997) and earlier editions. 2000 Forecasts: EIA, Annual Energy Outlook 1998 (AEO) (December 1997). When regions

differed between the Natural Gas Annual and the AEO, regional production volumes were projected for 2000 by applying the growth factor for the

AEO region between 1996 and 2000.

adequate domestic gas supplies through the near-term increased demand for U.S. gas deliverability through the year

perspective of the present analysis. 2000. Of the 7.1 Bcf per day (2.6 Tcf) in additional U.S. gas 16

While higher gas production in the lower 48 States from Canada are likely to represent about two-fifths of supply

contributed to increased U.S. gas supplies between 1990 and growth. Key domestic regions contributing to the supply rise

1996, the source of the largest portion of the increase was are the offshore and Permian Basin regions with 15 and

imports from Canada. Benefiting from strong U.S. demand 10 percent of the total increase, respectively (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 producing gas

accounted for about two-fifths of the increase in U.S. gas wells and gas-condensate wells, as well as a very large

supplies during this period. By 2000, imports of natural gas number of oil wells, yielding approximately 50 Bcf of natural

from Canada are projected to account for 16 percent of U.S. gas per day (18.4 Tcf per year). The largest gas-producing

gas supplies, more than double their 1990 share. region in the lower 48 States is the offshore region, followed

The concentration of increased gas supplies through 2000 in Permian Basin, and the Rockies. Together, these five regions

a small number of areas—Canada, the Rocky Mountain area, accounted for 81 percent of total U.S. dry gas production in

the Permian Basin, the San Juan Basin of New Mexico, and 1996. Eighty-six percent of U.S. consumption is met by

the offshore/onshore Gulf—raises concerns about the ability domestic producers, while the remainder is imported mostly

of the pipeline system and other infrastructure to meet from Canada. The following sections highlight the

supplies anticipated between 1996 through 2000, imports

17

by the onshore Gulf Coast, the Anadarko/Arkoma Basins, the

contribution of each major supply region to gas supplies and

deliverability in the lower 48 States.

Remaining recoverable gas resources are those volumes producible with 16

current recovery technology and efficiency but without reference to economic

viability. The estimate of 929 trillion cubic feet of remaining recoverable gas

resources is published in the report Potential Supply of Natural Gas in the

United States, Potential Gas Agency, Colorado School of Mines (March Energy Information Administration, Natural Gas Annual 1996,

1997). DOE/EIA-0137 (Washington, DC, September 1997).

17
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

Offshore Gulf of Mexico

The top gas-producing region in the lower 48 States is the

offshore region, where production flows almost exclusively

from the Offshore Gulf of Mexico. The Gulf accounted for

almost 30 percent of natural gas production (Figure 3) and

more than one-fifth of proved reserves (Table 3) in the 18

lower 48 in 1996. The recent rebound in offshore exploration

and development activity is likely to make the offshore region

an important source of increased gas supplies during the late

1990s. Recent changes in the sources of gas production in the

Gulf in favor of associated gas and deep water gas have major

implications for future gas deliverability from this region and

its impact on regional markets.

Major plays in the Gulf of Mexico 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 Mexico and includes fields in waters deeper than

600 feet; estimated productive capacity in the Flexure Trend

was about 1.2 Tcf in 1996. The Norphlet Trend is an 19

extension of the Flexure Trend stretching from Alabama to

Florida containing fields at 600 to 2,000 feet of depth.

Production in the Norphlet Trend was about 1 Tcf in 1996.

The Destin Dome, a part of the Norphlet Trend located off the

coast of the Florida Panhandle, is estimated to contain 3 Tcf

of potential reserves. However, significant production here is

not likely to begin until around 2000 and will therefore have

minimal impact on U.S. gas deliverability in the near term.

The collapse of oil and gas prices in the mid 1980s caused a

reduction in overall exploration and development activities in

the Gulf that continued into the early 1990s. As the average

U.S. wellhead price fell by more than two-fifths in real terms

(1996 dollars) between 1985 and the early 1990s, offshore 20

gas production was hit harder than onshore production

because of the rapid depletion of known deposits in shallow

waters and higher increased risks and costs associated with

exploration and development of gas in deep water. Between

1990 and 1992, offshore gas production declined by 8 percent

because of the lack of reserves replacement. Total offshore

reserves shrank 10 percent between 1990 and 1992.

The large fields in the deep waters, combined with costcutting new technologies, have greatly improved the

economics of offshore gas production, raising offshore output

more than 13.0 percent between 1992 and 1996 to a level of

15.0 Bcf per day (5.5 Tcf per year). A 12-percent increase in

average gas wellhead prices over the average from 1990

through 1992 (in constant 1996 dollars), coupled with a onethird decline in finding costs (also in 1996 dollars),

contributed to a dramatic improvement in the profitability of

offshore gas production. According to one source, offshore 21

gas production by 1995-96 was profitable at average wellhead

prices of only $1.75 per thousand cubic feet, down from a

profitability threshold estimated at $2.50 per thousand cubic

feet (in current dollars) in 1991-92. With 1996 U.S. wellhead

prices averaging $2.17 per thousand cubic feet, offshore gas

production had become profitable after a high degree of

unprofitability during the late 1980s and early 1990s.

The very high exploration and development (E&D)

expenditures associated with offshore projects, more than

$1 billion in some cases, are declining generally as companies

gain experience with more challenging deep water and subsalt

projects. Both project time horizons and platform costs are

shrinking dramatically. For example, the capital portion of

daily production costs for Shell’s Ursa tension leg platform

(TLP), due to begin production in 1999, is projected to be

slightly more than half that of Auger, Shell’s first TLP

installed in 1994. Offshore projects partially compensate for 22

higher upfront expenditures with faster recovery of reserves

through higher flow rates. The faster depletion of offshore

wells requires more continuous exploration activity to

maintain production levels. The Outer Continental Shelf

(OCS) Deep Water Royalty Relief Act (DWRRA), signed in 23

November 1995, has also improved the economics of offshore

production. The DWRRA provides for a waiver of royalty

payments for production from new leases and certain other

deep water leases.24

Overall, offshore gas production is projected to grow

7 percent from 15.0 Bcf per day (5.5 Tcf per year) in 1996 to

16.1 Bcf per day (5.9 Tcf per year) in 2000. A key source of

expanded production is likely to be associated-dissolved (AD)

gas from crude oil production (accounting for one-fourth of

the incremental production), although expanded output of

Proved reserves of natural gas are the estimated quantities which analysis royalty relief. In particular, fields that did not produce prior to November 28, 18

of geological and engineering data demonstrate with reasonable certainty to 1995, and meet Minerals Management Service (MMS) economic

be recoverable in future years from known reservoirs under existing economic determinations may receive royalty suspension volumes of at least 17.5 million

and operating conditions. barrels of oil equivalent (BOE) in 200 to 400 meters of water, 52.5 million

WEFA, Natural Gas Outlook (Spring/Summer 1997), p. 6.9. BOE in 400 to 800 meters of water, and 87.5 million BOE in more than 800 19

Energy Information Administration, U.S. Crude Oil, Natural Gas, and meters of water. 20

Natural Gas Liquids Reserves, Annual Report 1996, DOE/EIA-0216(96) “Deepwater royalty relief product of 3 1⁄2 year U.S. political effort,” Oil

(Washington, DC, December 1997), p. 10. and Gas Journal (April 1, 1996), pp. 45-56.

James Dodson and Leonard LeBlanc, “U.S. Gulf Rebound to Continue 21

in 1995,” Offshore (January 1995), p. 20.

“Deepwater, subsalt projects open new era for Gulf of Mexico actions,” 22

Oil and Gas Journal (January 20, 1997), p. 37.

The law provides royalty relief to oil and gas fields in the Central and 23

Western Gulf of Mexico that would not be economic to produce without

24
 







































     











Offshore

Gulf Coast

Anadarko/Arkoma

Rockies

Total lower 48 production is 18.4 trillion cubic feet

East Texas

San Juan Basin

Appalachian

(16.0%)

(8.2%)

(8.8%)

(6.3%)

(5.4%)

(2.7%)

(29.9%)

(18.2%)

Other (4.5%)

Permian

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

Figure 3. Lower 48 Natural Gas Production by Region, 1996

(Share of Total in Percent)

Source: Energy Information Administration. Total 1996 Production: Natural Gas Annual 1996 (September 1997). Shares by Region:

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 (December 1997).

Table 3. Lower 48 Dry Natural Gas Proved Reserves and Reserves-to-Production Ratio, 1990-1996

Proved Reserves Proved Reserves-to-

(billion cubic feet) Production Ratio

Region 1990 1995 1996 1990 1995 1996

Gulf Coast 21,325 19,186 20,050 7.0 6.1 6.0

Anadarko/Arkoma 31,986 28,008 26,629 9.9 9.8 9.1

Permian Basin 15,718 13,534 14,053 9.8 8.5 8.6

Rockies 16,009 21,002 21,663 18.1 14.1 14.4

East Texas 10,216 10,376 11,083 9.5 9.2 9.6

San Juan Basin 14,004 14,624 13,695 28.3 14.9 13.8

Appalachian Basin 5,633 7,068 7,674 11.7 15.3 15.2

Other Onshore 9,584 8,027 8,653 11.7 10.1 10.4

Total Onshore 124,475 121,825 123,500 10.7 9.8 9.6

Offshore 35,571 33,824 33,680 6.8 6.6 6.1

Total Lower 48 160,046 155,649 157,180 9.5 8.9 8.5

Source: Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 (December 1997).
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

deep water and subsalt gas also contribute to production startups expected from 1997 through 2000. Activity in the

gains. deep waters of the Gulf of Mexico is expected to remain

A more than one-third increase in Gulf oil production since act incentives. The number of blocks receiving bids in the

1990 has led to higher output of AD gas, which reached sales since the DWRRA was signed in November 1995 has

2.2 Bcf per day (0.8 Tcf), or 15 percent of total offshore gas risen substantially, with blocks in at least 800 meters

production in 1996. Based on Energy Information numbering seven times the earlier count (Table 4). Some of

Administration (EIA) projections of Gulf oil output through the deep water capacity coming on stream during the 1990s

2000, AD gas will rise by another 0.25 Bcf per day. The is replacing depleted deposits in shallower water. Deep water 25

considerable future potential of AD gas is demonstrated by its gas production will contribute to a net increase in offshore

large share of total offshore reserves, which grew from less production during the latter half of the decade.

than 20 percent in 1990 to 22.4 percent in 1996.

The growing influence of AD gas in the Gulf has provided thick sections of salt have made it possible to develop

producers with some logistical challenges and has possible resources under sheets of salt that are believed to extend

implications for regional gas prices. Because natural gas is under more than half of the Gulf of Mexico. In 1993, the first

consumed in accordance with seasonal market demand, the subsalt find to be commercially developed, Mahogany, was

fairly steady recovery schedule of AD gas from oil projects discovered, followed by seven more in 1994 and 1995. Even

results in some gas being produced during periods of minimal though some initial successes generated considerable interest

demand. Such an inelastic production schedule, characteristic in the estimated 15 trillion cubic feet or more of undiscovered

of AD gas, could depress gas prices in the Gulf region during subsalt recoverable gas resources, significant exploratory

periods of minimal demand. risks remain and subsalt gas supplies are not expected to be as

Expanding production of AD gas in the Gulf of Mexico has per day of total additional production capacity is likely from

therefore led to increased use of storage along the Gulf Coast, new subsalt gas through the year 2000. In the longer term,

so that producers can better match supplies to seasonal which is beyond the scope of this report, subsalt gas

demand. The anticipated increase in AD gas production production could have greater impact on offshore gas

through 2000 is being accompanied by underground storage deliverability.

expansions under development in Texas and Louisiana with

a combined daily deliverability of 2 Bcf per day. The steady movement of gas production into deeper, more 26

Underground storage capacity is also being expanded near remote environments further offshore raises several

major market areas in the Northeast and Midwest, where up challenges related to delivery of gas from the field. They

to 1.5 Bcf per day in daily deliverability could be added in include building the offshore pipeline network to bring the

each region by 2000. However, most likely not all planned new deep water gas ashore and expanding existing onshore

capacity additions will be realized. pipeline capacity to accommodate the additional gas (see

Other offshore production trends affecting gas deliverability 1997-2000").

include 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 producing gas in

the Gulf since the late 1970s, their role in offshore gas

production was minimal until recent technological advances,

such as improved 3-D seismic surveys and floating

production systems (see Box, “Technological Improvements”), allowed for the discovery and development of

several large deep water deposits. By 1996, 20 new deep

water prospects began producing, with a similar number of

27

strong as leasing activity has responded to the royalty relief

Advances in 3-D seismic interpretation and drilling through

significant in the near term as deep water gas. Less than 1 Bcf

Appendix B, “Natural Gas Pipeline and System Expansions,

Onshore (Texas and Louisiana) Gulf

Coast

The Gulf Coast region, containing the coastal East and

Southeast Texas (Railroad Commission Districts 1, 2, 3, and

4), and Southern Louisiana, produced 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

production grew by roughly 6 percent between 1990 and 1996

and at 9.1 Bcf per day (3.3 Tcf per year) accounted for nearly

Energy Information Administration, Annual Energy Outlook 1998 With 25

Projections to 2020, DOE/EIA-0383(98) (Washington, DC, December 1997).

See Energy Information Administration, “U.S. Underground Storage of Chris C. Oynes, Regional Director, Gulf of Mexico Region, Minerals 26

Natural Gas in 1997: Existing and Proposed,” Natural Gas Monthly, Management Service, presentation at the OCS Workshop, American

DOE/EIA-0130(97/09 (Washington, DC, September 1997), pp xxi-xli. Association of Professional Landsmen (Houston, TX, January 22, 1998). 

27
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

Table 4. Central and Western Gulf of Mexico Lease Sales Before and After the Royalty Relief Act

Block Water Depth

 (meters) 1994 1995 1996 1997

Number of Blocks Receiving Bids

0-200 490 516 637 542

200-400 18 50 69 52

400-800 28 83 113 104

800+ 49 214 722 1,138

All Depths 585 863 1,541 1,836

Note: The Outer Continental Shelf Deep Water Royalty Relief Act was signed in November 1995.

Source: Derived from a speech by Chris C. Oynes, Regional Director, Gulf of Mexico Region, Mineral Management Service, to the OCS

Workshop, American Association of Professional Landsmen (Houston, TX, January 22, 1998).

16 percent 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 March 31), declined from 23 percent of

located in southern Texas. They produced a daily average of total deliverability in 1990 to an estimated 14 percent in 1996

1.1 and 0.3 Bcf of wet gas, respectively, in 1996 (Table 5). (Table 6). 28

Most of the onshore Gulf Coast’s production is from

nonassociated gas, with AD gas accounting for only about

one-tenth of regional gas production and reserves.

A high degree of exploration activity, enhanced by the use of

horizontal and multilateral drilling, is yielding impressive

results, particularly around the Austin Chalk Trend. In March

1997, one well set an onshore U.S. horizontal well record,

flowing an average of 84 million cubic feet per day, which

was exceeded by another with an average flow of 100 million

cubic feet per day in April 1997. Technology has also been

employed in the onshore Gulf region to expand flow at

producing fields, with a major developer of the Wilcox/Lobo

Trend achieving a 75-percent success rate in 1994 using 3-D

seismic technology and improved fracturing fluids.

Proved reserves in the onshore Gulf Coast region declined

between 1990 and 1996 to the equivalent of 6 years’ worth of

production, the lowest reserves-to-production ratio among

major onshore gas-producing regions (Table 3). Reserves

declined by more than 15 percent between 1990 and 1993 but

have since partially recovered to 20.1 Tcf in 1996 as

increased exploration activity from 1994 through 1996 found

increased 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

production in the onshore Gulf Coast region is forecast to rise

almost 3 percent to 9.4 Bcf per day (3.4 Tcf per year).

Estimates of productive capacity show that surplus wellhead

Anadarko and Arkoma Basins

The Anadarko/Arkoma region comprises Oklahoma, Kansas,

Arkansas, and the Texas Panhandle area (Railroad

Commission District 10). It was the largest onshore gasproducing region in 1990, when production averaged 9.1 Bcf

per day (3.3 Tcf per year) (Table 2). However, a sharp

production decline in Oklahoma reduced the region’s gas

production by more than 12 percent between 1990 and 1996

to a level of 8.0 Bcf per day (2.9 Tcf per year). A major factor

in declining regional gas output was a nearly 30-percent

contraction of productive capacity between 1990 and 1996.

By the mid-1990s, Anadarko/Arkoma had fallen to second

place 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-percent drop in

Anadarko/Arkoma proved reserves, from 32.0 Tcf in 1990 to

26.6 Tcf in 1996 (Table 3).

The largest gas field in Anadarko/Arkoma is the giant

Hugoton gas field in Kansas, which dates from 1922

(Table 5). Despite its age, Hugoton was the second largest

U.S. gas field ranked by annual production in 1996 (1.5 Bcf

per day of wet gas) and is the largest U.S. field in terms of

cumulative production (about 22 Tcf). Hugoton, whose

production comes from low permeability sandy carbonate

reservoir rocks, occupies much of the western half of Kansas

and extends south into Oklahoma and the Texas Panhandle.

Hugoton’s gas output has been raised in recent years through

the practice of more intensive drilling in existing fields and

through some new finds, including those along the Eubank

channel. This helped to offset significant declines in

production at other Anadarko/Arkoma fields, particularly in

Wet gas refers to produced natural gas that contains liquid hydrocarbons 28

that are removed at a natural gas plant. Dry gas is the gas remaining after

liquids removal.
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

Table 5. Top 10 Fields in the Lower 48 States Ranked by Natural Gas Production, 1996

(Billion Cubic Feet)

Rank Field Name Discovery Production Production State Producing Area (percent)

Location

Year of Daily Annual Production

1996 Share of

Average 1996 Lower 48

1 Basin NM San Juan Basin 1947 1.83 668.8 3.5

2 Hugoton Gas Area KS/OK/TX Anadarko/Arkoma 1922 1.52 558.0 2.9

3 Blanco NM/CO San Juan Basin 1927 1.50 549.0 2.8

4 Giddings TX Onshore Gulf Coast 1960 1.05 386.0 2.0

5 Carthage TX East Texas 1936 0.56 203.5 1.1

6 Mobile Bay AL Offshore Gulf of Mexico 1985 0.36 131.3 0.7

7 Panhandle West TX Anadarko/Arkoma 1918 0.35 129.8 0.7

8 Bob West TX Onshore Gulf Coast 1990 0.33 119.8 0.6

9 Panoma Gas Area KS Anadarko/Arkoma 1956 0.31 112.7 0.6

10 Green Canyon Blk 116 -- Fed. Offshore - Gulf of Mexico 1983 0.25 92.1 0.5

Total -- -- -- 8.06 2,951.0 15.3

Note: Gas is wet after lease separation.

Source: Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 (December 1997).

Table 6. U.S. Natural Gas Productive Capacity Utilization and Surplus Deliverability by Region, 1990,

1995, and 1996

Productive Capacity Utilization Surplus Deliverability

(percent as of January) (percent as of January)

Region 1990 1995 (estimate) 1990 1995 (estimate)

1996 1996

Gulf Coast 79.5 81.1 83.3 23 18.7 13.8

Anadarko/Arkoma 72.3 80.5 88.7 28 19.5 11.3

Permian Basin 78.5 79.8 80.4 20 19.0 17.9

Rockies 81.5 81.1 85.8 19 18.9 14.2

East Texas 79.4 81.1 83.5 23 18.7 13.8

San Juan Basin 73.6 76.3 75.8 26 23.7 24.2

Offshore 78.5 75.9 70.4 22 24.1 29.6

Total Lower 48 77.3 79.3 79.8 23 20.7 20.2

Note: Utilization factors for the Gulf Coast, Permian Basin, and East Texas regions are average factors for the relevant States weighted by the

relative dry gas production volumes in the region.

Source: Energy Information Administration, Natural Gas Productive Capacity for the Lower 48 States (December 1996).

Oklahoma. In October 1997, Mobil and Anadarko Petroleum with a stabilization of productive capacity, should keep

Corp. announced that they would jointly exploit deeper Anadarko/Arkoma’s gas production level at about 8.1 Bcf per

horizons in Hugoton, providing further indication of future day (3.0 Tcf 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 produced

a daily average of 0.36 Bcf and the Panoma gas area in

Kansas produced another 0.31 Bcf daily on average in 1996.

Contracting productive capacity reduced Anadarko/Arkoma’s

surplus deliverability from 28 percent in January 1990 to

about 11 percent in January 1996 (Table 6). Output gains

from infill drilling and some new finds at Hugoton, combined

Permian Basin

The Permian Basin region spans from eastern New Mexico to

western Texas (Railroad Commission Districts 7B, 7C, 8, 8A,

and 9). Gas production declined between 1990 and 1996,

from 4.6 to 4.4 Bcf per day (1.7 to 1.6 Tcf per year), while

proved reserves declined by about one-tenth to 14.1 Tcf in
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 	

1996 (Table 3). The top five fields—Gomez, Spraberry Trend A growing portion of Rockies’ natural gas production during

Area, Puckett, Sugg Ranch, and Keystone—account for about the early 1990s came from coalbed methane (Figure 4),

one-quarter of total Permian Basin gas production and one- spurred by a Federal tax credit for natural gas produced from

third of the region’s proved reserves. AD gas accounts for coal seam wells with initial drilling prior to January 1, 1993.

about two-fifths of gas production and reserves in the Permian This tax credit extends up to 10 years for any producing well

Basin and is almost as large in absolute terms (about 2 Bcf per so it will affect production on at least some portion of coalbed

day) as offshore AD gas output. production through 2002. Expiration of the qualifying period

Improvements in both seismic technology and drilling likely affect the future volume of coalbed methane production

methods could give the Permian Basin new life during the late in both the Rockies and San Juan Basin, another region which

1990s. One play, Texas’ Val Verde Basin, a sub-basin within is the leading U.S. producer of coalbed methane. The Rocky

the Permian, may have world-class potential. While Val Mountain area is also a significant producer of AD gas, which

Verde has yielded finds such as Puckett since the 1950s, accounted for 12 to 15 percent of total regional output in the

improved seismology has shown huge, previously unknown mid-1990s and about one-tenth of reserves.

structures in the Ellenburger formation and thrusted rocks

extending further east and north in Val Verde than previously Proved gas reserves in the Rocky Mountain area grew by onerealized. Thrusted Shawn reservoirs, limestones that produce third from 16.0 trillion cubic feet (Tcf) in 1990 to 21.7 Tcf in

either from fractured intervals or reefs, are at 10,000 feet and 1996 (Table 3). Large recent reserve gains at the Big Pineyoffer more immediate economic opportunity than deeper LaBarge Field have made it the largest field in terms of

plays. In addition, Wolfcamp (also known as Canyon Sand) reserves in Wyoming, while further reserve increases are also

is a low-risk, limited-potential play that is popular because of likely to come from the Madden Field and Moxa Arch

success rates of 90 percent in some cases. Extension. The Madden Field could become a very profitable

The potential from these plays, combined with one of the of the formation through just one or two holes drilled at the

highest surplus deliverability measures among producing top of the reservoirs. The Moxa Arch Extension ranks high in

regions (an estimated 18 percent in 1996), should help to raise terms of gas produced per drilling dollar, but this does not

Permian Basin gas production more than 10 percent between include heavy associated costs of fracturing the tight

1996 and 2000 to 5.2 Bcf per day (1.9 Tcf per year) (Table 2). formations that are common to this play. Other possible

Rocky Mountain Area

The Rocky Mountain area, including Colorado, Utah, and

Wyoming, was one of the fastest-growing U.S. producing

regions between 1990 and 1996 and has the potential for

further output gains through 2000. Gas production increased

nearly two-thirds since 1990 from 2.5 Bcf per day (0.9 Tcf

per year) to 4.1 Bcf per day (1.5 Tcf per year) in 1996

(Table 2). Major plays in the Rockies include the Wind River

Basin, the Labarge and Big Piney Projects, the Overthrust

Belt, the Green River Basin, and the Powder River Basin.

The Rocky Mountain area is one of the newest major gas

producing 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 producing fields in 1996 included

Wattenburg in Colorado (0.24 Bcf per day), Anschutz Ranch

East in Utah/Wyoming (0.23 Bcf per day), Whitney CanyonCarter Creek in Wyoming (0.22 Bcf per day), and Bruff in

Wyoming (0.14 Bcf per day).29

for the tax credit has reduced drilling activities, which will

play because it might be possible to draw most of its gas out

sources of increased gas in the near term include coalbed

methane in the Powder River play of Wyoming, where

productive capacity rose from near zero in 1990 to 28 million

cubic feet per day in 1996, with at least another 35 million

cubic feet per day waiting for connection and pipeline

hookup.

As a result of reserve growth, the 1996 reserve-to-production

ratio in the Rocky Mountain area was among the highest in

the lower 48 States at 14 (Table 3). Large reserves and output

from new finds are expected to contribute to an 11-percent

growth in Rockies’ gas production between 1996 and 2000 to

around 4.6 Bcf per day (1.7 Tcf per year) in the latter year

(Table 2). The rate of growth in Rockies’ gas output during

the latter half of the 1990s is quite impressive given the

number of impeding factors. Such factors include the phaseout of the coalbed methane tax credit, saturation of Western

markets, and the cost of building additional pipeline capacity

to redirect more Rockies’ gas eastward towards high-demand

markets, rather than due to any shortage of gas supplies.

East Texas

The East Texas region includes Northeast Texas (Railroad

Commission Districts 5 and 6) and northern Louisiana. Its gas

Energy Information Administration U.S. Crude Oil, Natural Gas, and 29

Natural Gas Liquids Reserves, Annual Report 1996 (Washington, DC,

December 1997), p. 58.
1990 1991 1992 1993 1994 1995 1996

0

100

200

300

400

500

600

Billion Cubic Feet

New M exico

Colorado

Alabam a

Other

Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

Figure 4. U.S. Coalbed Methane Output, 1990-1996

Note: Other includes Kansas, Oklahoma, Pennsylvania, Utah, Virginia, West Virginia, and Wyoming.

Source: Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 (December 1997).

production increased by one-tenth from 3.0 Bcf per day mainly accounted for by two giant gas fields—Basin and

(1.1 Tcf per year) in 1990 to 3.2 Bcf per day (1.2 Tcf per Blanco—that are two of the three largest in the lower 48

year) in 1996 (Table 2). Nearly one-half of production and States. The Basin Field, first drilled in 1947, was formed in

over one-half of reserves in East Texas are accounted for by February 1961 by combining several existing fields. The

five fields: Carthage, Oak Hill, Willow Springs, Whelan, and Blanco Field encompasses much of the central San Juan

Hawkins. Carthage is the largest among them; in 1996, it Basin.

produced 203.5 Bcf (wet gas, 0.56 Bcf per day) and was the

fifth largest U.S. gas field that year in terms of production. Much of the increase in gas production in the San Juan Basin

East Texas is one of the few onshore regions to register Production gains were strongest until the end of 1992, when

substantial new field finds in recent years. Drilling in the phase-out of the coalbed methane tax credit began. Coalbed

Cotton Valley lime reef play resulted in 25 discoveries methane production grew further in the years 1993 through

reported out of 45 wells as of mid-1997 for a 55-percent 1996, owing to subsequent completion of wells spudded prior

success rate. At least 550 Bcf of reserves have been found at to the tax credit deadline and as these wells proceeded

the Cotton Valley Lime reef play, helping to expand the through the dewatering phase early in their production cycle.

region’s reserves 7 percent to 11.1 Tcf in 1996 after little San Juan Basin production increases were also the result of

change between 1990 and 1995. Overall, East Texas gas well recompletions in the basin’s deeper tight sands

output is likely to increase moderately by about 0.1 Bcf per formations as operators employed new technologies to

day to just under 1.2 Tcf per year in 2000. increase gas flow.

San Juan Basin

The San Juan Basin in northwestern New Mexico, like the

Rockies, has substantially increased production since the late

1980s. Production almost doubled between 1990 and 1996 to

2.7 Bcf per day (1.0 Tcf per year) in 1996 (Table 2) and is

during the 1990s has come from coalbed methane wells.

Expiration of the coalbed methane tax credit had an

immediate impact on San Juan Basin proved reserves, which

contracted 13 percent between 1992 and 1996 (in part

because of downward revisions as some coalbed fields were

considered no longer economical, especially in a pipeline

constrained market) after expanding by a similar percentage

between 1990 and 1992. This left the region’s reserves at
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

13.7 trillion cubic feet in 1996, compared with 14.0 in 1990. expected to far exceed the expected modest increment to

Stagnant reserves are not likely to limit the San Juan Basin’s Appalachian Basin production during the 1997 through 2000

gas production in the near term, because its reserves still period, attractive opportunities are likely for gas suppliers

represent almost 14 years’ worth of production (well above from other regions of the lower 48 and from Canada.

the U.S. average). Gas output is projected to increase about

3 percent per year on average during the late 1990s to 3.0 Bcf

per day (1.1 Tcf per year) in 2000 as a result of reduced

coalbed methane activity, well below its double-digit annual

growth rate during the early 1990s.

As with the Rockies region, the major constraints on future

growth of gas production in the San Juan Basin are more

related to market conditions and infrastructure than to

physical output capability. With peak productive capacity

utilization in the San Juan Basin running below 80 percent in

the mid-1990s, surplus deliverability was the highest of any

major gas-producing basin at over 20 percent. Thus, a major

determinant of future gas output here is likely to be the pace

of expansion of pipeline capacity to carry the gas to major

markets in the Northeast and Midwest given the saturation of

California and other Western markets.

Appalachian Basin

The Appalachian Basin extends from the Middle Atlantic to products.

the South Atlantic Census Bureau divisions and is the largest

gas-producing basin close to major markets in the Northeast. Since 1987, U.S. gas imports from Canada have nearly tripled

This region is a minor producer of gas, providing only about to around 8 Bcf per day (2.9 Tcf per year) in 1996,

2 percent of total lower 48 gas supplies, but it is a major accounting for 13.5 percent of U.S. gas supplies. Growth was

source of gas for the large urban areas of the Northeast. swiftest between 1990 and 1995, when imports of Canadian

Pennsylvania and West Virginia account for the majority of gas increased at a 14-percent average annual rate. Relative

the Appalachian Basin’s natural gas production, while price movements helped to stimulate increased U.S. gas

Virginia has increased production following sizable new imports from Canada, since the average wellhead price in the

finds, including coalbed methane deposits. lower 48 changed from being 11 percent cheaper than

A portion of the region’s 1.4 Bcf per day gas output comes expensive by 1996 (Figure 5).

from unconventional sources, such as Devonian Shale. In

December 1992, the National Petroleum Council estimated Canada produced about 5.6 Tcf of gas in 1996, equivalent to

that the Devonian Shale in this area contains about 27 Tcf that about 30 percent of lower 48 production. Canadian gas

could be produced using known technology. This compares production is centered in the Western Canada sedimentary 30

with proved reserves in 1996 of 7.7 Tcf, which is one-third basin, 95 percent of which occurs in the western provinces of

larger than the 1990 level mainly because of the new finds in Alberta (83) and British Columbia (12). Total Canadian gas

Virginia. production was 56 percent higher in 1996 than in 1990, while

Higher reserves raised the Appalachian region’s ratio of 23 percent during the same period. As a result, domestic use

proved reserves to production to 15 in 1996, the highest in the of natural gas in Canada (47 percent of final gas sales occurs

lower 48. Such a ratio indicates high likelihood of production

increases during the late 1990s, with Appalachian Basin gas

output forecast to grow about 16 percent to 1.6 Bcf per day

(0.6 Tcf per year) in 2000. With demand in the Northeast

Canadian Supplies

Sharp increases in natural gas imports from Canada have

made Canada the third most important source of U.S. gas

supplies after the offshore and Gulf Coast regions. Various

factors have contributed to the strong growth in U.S. natural

gas imports from Canada over the past decade, including: 31

 The 1985 Agreement on Natural Gas Markets and Prices

that changed Canada’s pricing policy from governmentadministered to market-oriented pricing

 The “market-based procedure” for determining the

surplus Canadian natural gas available for export that

replaced the previous reserves-to-production (R/P) ratio

procedure in 1987

 The U.S.-Canadian Free Trade Agreement (CFTA) of

1988 that prohibited most trade restrictions on energy

imported Canadian gas in 1990 to being 11 percent more

natural gas end-use consumption in Canada grew by only 32

National Petroleum Council, The Potential for Natural Gas in the United Canadian Association of Petroleum Producers, CAPP 1996 Statistical 30

States: Source and Supply (1992), p. 111. Handbook (Calgary, Alberta, Canada, 1997), Tables 3.10a, 6.3a, and 9.1a.

For more detail see Energy Information Administration, Natural Gas 31

1996 Issues and Trends, DOE/EIA-0560(96) (Washington, DC, December

1996), p. 95. 32
1990 1991 1992 1993 1994 1995 1996

0

0.5

1.0

1.5

2.0

2.5

Price Ratio

Ratio of Canadian to U.S. Price

1990 1991 1992 1993 1994 1995 1996

0

0.50

1.00

1.50

2.00

2.50

Price in 1996 Dollars

Average Canadian Gas Import Price

Average U.S. Wellhead Price

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System

Figure 5. Comparison of Average U.S. Natural Gas Wellhead Price and Canadian Natural Gas import

Price, 1990-1996

Note: Prices in 1996 dollars based on appropriate gross domestic product (GDP) deflators as published in the Survey of Current Business

(August 1997) and distributed on the Internet site www.bea.doc.gov.

Source: Energy Information Administration (EIA), Natural Gas Annual (September 1997).

in the eastern provinces of Ontario and Quebec) fell commercial production by late 1999 and contribute

from representing 60 percent of Canadian production in 1990 significantly to North American gas supplies in the longer

to only 49 percent in 1996. Since 1990, the TransCanada term, although their impact on U.S. markets through 2000

Pipeline system has substantially increased its capability to will be limited.

move supplies from the Alberta/Saskatchewan border

(currently 7.2 Bcf per day during the winter) but not rapidly The rising importance of U.S. export markets to Canadian gas

enough to meet both the growth in domestic demand and producers is illustrated by the fact that more than half of

export capacity. As a result, TransCanada Pipeline and several Canadian gas production by the mid-1990s was destined for

other firms have developed plans to expand domestic and export to the United States compared with two-fifths in 1990

export capability over the next several years to meet the (Figure 6). In 1996, growth in Canadian gas exports to the

demands of Western producers and customers in Canadian United States slowed to 2.4 percent primarily because of

Eastern markets. bottlenecks resulting from existing pipeline capacity

While the more than 50-percent growth in Canadian gas imports of Canadian gas in 1996 continued to decline relative

production reduced the country’s reserves-to-production ratio to the average wellhead price in the lower 48. The downward

from almost 26 in 1990 to 12 in 1996, the Canadian Gas movement in the price for Canadian gas relative to the U.S.

Potential Committee has estimated remaining marketable gas, price was influenced also by a significant shift in the

including discovered reserves and undiscovered potential in exchange rate, with the Canadian dollar falling from $0.86US

established exploration plays and coalbed methane, at in 1990 to $0.73US in 1996. Favorable price trends

about 570 trillion cubic feet. This suggests that Canadian combined with continued demand growth in the lower 48 are 33

supplies are more than sufficient to meet expected domestic likely to raise imports of Canadian gas by over one-third

and export demands well past the year 2000. New gas finds between 1996 and 2000 to about 10.7 Bcf per day (3.9 Tcf

off Canada’s Atlantic shores are expected to begin per year) in 2000.

constraints. Relative price data show that prices for U.S.

34

35

“Where future Canadian gas supply will originate,” Oil and Gas Journal See Energy Information Administration, Annual Energy Outlook 1998 33

(December 15, 1997), p. 67. (December 1997), p. 118.

Canadian Association of Petroleum Producers, CAPP 1996 Statistical 34

Handbook (Calgary, Alberta, Canada, 1997), Table 5.5c. 35
1990 1991 1992 1993 1994 1995 1996

0

1

2

3

4

5

6

Billion Cubic Feet

Exports to United States

Canadian Gas Use

Total

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

Figure 6. Canadian Gas Exports to the United States and Total Canadian Gas Production, 1990-1996

Note: Canadian gas use was calculated by subtracting exports to the United States from total Canadian gas production.

Sources: Canadian Gas Exports to United States: Energy Information Administration, Natural Gas Annual 1996 (September 1997) and

earlier editions. Canadian Gas Production: Canadian Association of Petroleum Producers (CAPP), Statistical Handbook 1996 (September

1997). 

Receipt Capabilities

Wellhead gas productive capacity is only one of the elements

necessary to meet U.S. natural gas demand. Because major

market areas are not usually located in close proximity to

supply/production 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, which is

relevant to this chapter, requires adequate pipeline receipt

capability to facilitate the movement of the natural gas from

producing fields to the interstate pipeline system.

In the United States, natural gas typically moves from major

supply areas in Texas, Oklahoma, Louisiana, Wyoming,

Kansas, Colorado, New Mexico and the Offshore Gulf of

Mexico 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 Pacific Coast, which are saturated with gas

from Canada. Additionally, the dramatic increase in gas

imports from Canada during the past decade has opened up

new supply routes from Western Canada to the lower 48, with

the swiftest growth in route volume occurring into the

Northeast.

While wellhead gas productive capacity and import capacity

were sufficient to meet U.S. demand under normal weather

conditions through the end of 1997, unusually high peak-day

or peak-week heating or cooling demand required deliveries

from storage or peak-day shaving. Limited pipeline receipt

capabilities in key production areas, such as the Gulf of

Mexico, the Northern Rocky Mountains, and the San Juan

Basin, compromise the ability to meet peak demand. And

with total U.S. gas supplies expected to increase by more than

12 percent between 1996 and 2000, the additional 7 Bcf per

day of supplies will require expansion of existing transport

and storage capacity. Several projects have been proposed

that will expand the receipt capability of the interstate

pipelines transporting natural gas from producing to

consuming areas in the United States, including gas imports

via pipeline from Canada.

Offshore and Onshore Gulf Northward

The offshore and onshore Gulf region, which together provide

almost half of all natural gas produced in the lower 48, supply

a large portion of this gas to other regions. These two regions

account for a large portion of the 12.6 Bcf per day on average
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

transported from the Southeast to the Midwest and Northeast, to 1.5 Bcf of daily deliverability from storage in the

where rising shipments brought average usage rates to 82 to Southwest and up to 1 Bcf per day from storage in the

86 percent in 1996. Northeast (mainly in New York and Pennsylvania). By

Despite an already well-developed gas infrastructure 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. Because storage is generally cheaper

sufficient offshore pipeline receipt capacity to support the to build than laying new pipeline, this is an economically

rapidly increasing wellhead productive capacity, particularly attractive option for the short term. In the longer term,

offshore. Offshore pipeline construction increased more than however, marginal increases from greater usage of existing

20 percent between 1990 and 1995, followed by completion pipelines may not be sufficient to accommodate the expected

of two large expansion projects in 1996—the Shell Gas magnitude of produced gas in certain regions.

Pipeline and the Centana Main Pass/Viosca Knoll Gathering

System. Several new pipeline projects were completed in

1997, including the Garden Banks Offshore System, the

Manta Ray Gathering System, the DIGS Main Pass Gathering

System, the Discovery Pipeline, and the Nautilus Pipeline.

As a result of this construction, nearly 20 Bcf per day of

pipeline capacity extends onshore from the offshore Gulf

region, mostly to Louisiana. Major pipelines that receive

onshore and offshore Gulf gas for transportation to markets in

the Northeast and Midwest include ANR, Columbia Gulf,

Florida Gas, Koch Gateway, Southern Natural Gas, Tennessee

Gas, Texas Eastern, Transcontinental, and Trunkline systems.

Some of these pipeline systems, notably Tennessee and Texas

Eastern, are very large and were operating at nearly full

capacity in 1996 during peak periods.

Despite ambitious pipeline expansion plans to bring an

additional 3 Bcf per day or more of offshore gas ashore at

Alabama, Louisiana, and Mississippi by the year 2000, lack

of adequate capacity to transport the gas to markets in the

Northeast and Midwest could hamper future gas deliverability

from the Gulf. There are 10 proposed projects that would

bring more than 1.6 Bcf per day of additional gas ashore at

Louisiana and about 1.5 Bcf per day at Mississippi and

Alabama (see Appendix B, Table B2). Potential bottlenecks

may arise further downstream as existing pipeline capacity

into Mississippi and Arkansas is not expected to expand by

similar magnitude and could face average usage levels far in

excess of 90 percent.

An alternative solution, increased reliance on storage, could

allow for increased gas deliveries from the Gulf to the

Northeast without adding new pipeline capacity. A number of

new storage facilities, including high-deliverability salt

cavern storage, are being built both in the Northeast near the

consuming markets and on the Gulf coast near offshore

production areas. New salt cavern storage facilities expected 36

to be built during the years 1998 through 2000 could add up

moving the gas into markets such as the Northeast during

From the Rockies and San Juan Basin

Eastward

Despite strong growth in production and reserves in the

Rocky Mountain area and in the San Juan Basin of New

Mexico between 1990 and 1996, only a small portion of that

production saw its way to Midwest or Northeast markets.

Pipeline capability to move gas eastward from that area has

been limited as traditionally the production has been targeted

to Western markets. But with Western markets becoming

saturated, interest has increased in moving supplies eastward.

While the northern Rocky Mountain area has not experienced

receipt constraints for supplies moving westward, it has been

unable to gain access to Eastern markets because of limited

pipeline receipt capability. This constraint is expected to ease

as eastern access via the San Juan Basin has increased and

several expansion projects have been planned that will

increase pipeline capacity from the Rocky Mountains to hubs

serving the Midwest and East. Expansions completed in 1997

included KN Energy’s Pony Express line from Wyoming to

several long-haul pipelines running from the Permian Basin

to the Midwest and expanded capacity from the Overthrust

and Green River basins to the eastward-running Trailblazer

Line.

Sufficient new pipeline capacity is planned between 1998 and

2000 to accommodate the expected production increases in

the Rockies and San Juan Basin areas (almost 0.8 Bcf per day

additional) without major bottlenecks. According to 1996

data, the El Paso pipeline from the San Juan Basin of

New Mexico into Texas alone had nearly 1 Bcf per day of

unused capacity on average. Along with completion of the

TransColorado line ( 0.3 Bcf per day) to the San Juan Basin

running from Colorado’s Piceance Basin, Southwestern

Wyoming, and Utah’s Paradox and Uinta basins, this suggests

adequate receipt capability for the anticipated increase in San

Juan Basin output during the next 3 years. The Natural Gas

Pipeline Company of America’s Amarillo expansion would

help move these new supplies to the East through Chicago

from the Waha hub in Texas.

Energy Information Administration, “U.S. Underground Storage of 36

Natural Gas in 1997,” Natural Gas Monthly, DOE/EIA-0130(97/09)

(Washington, DC, September 1997).
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

Technological Improvements

A decade of technological improvements has reduced finding costs, raised the size of finds, and opened

new areas of exploration

The combined application of several new technologies over the last decade has contributed to U.S. gas production gains

during the 1990s in a number of ways. These technologies include enhancements to exploratory and developmental

activities, such as 3-D seismic and cross-well seismic surveys, improved drilling techniques through the use of horizontal

and multi-lateral drilling, and new offshore production systems that include floating and subsea assemblies.

Lower finding costs facilitated by wider use of 3-D seismic surveys and other new technologies have reduced production

costs and contributed to higher U.S. gas production during the 1990s.* Over the past decade, onshore finding costs have

been cut by more than half, while offshore finding costs have fallen even more sharply. As a result, offshore finding costs

converged with onshore finding costs in the mid-1990s after more than a decade of exceeding them by a considerable

margin (Figure 7). The nearly two-thirds reduction of offshore finding costs between 1986 and 1996 was a major factor

in the increased profitability of offshore gas production because offshore lifting costs are much lower and comprise a

smaller share of total production costs than with onshore production (Figure 8).

New technologies have redefined deep water drilling opportunities in the Gulf of Mexico. In 1996, dry gas productive

capacity in the Federal Offshore Gulf of Mexico region was nearly 30 percent of the productive capacity for the lower

48 States. The offshore region also had a higher average reserves addition per successful well, averaging more than

16 Bcf from 1992 through 1994. The importance of the offshore portion of total U.S. gas production is expected to rise

further through the year 2000 with new capacity due for startup from deep water and subsalt wells as well as continued

gains in AD gas output. Because of technological changes, deep water drilling is now taking place at previously

impossible water depths—for example, Shell’s Mensa at depths of more than 5,300 feet. Future plans call for even deeper

drilling, with Shell’s Couloumb and BAHA projects planned at 7,500 feet or more (Figure 9).

The technologies contributing to these breakthroughs include:

 3-D Seismic Surveys - 3D seismic surveys are conducted by use of meticulously spaced vibration-detecting

geophones to measure the feedback from a sequence of experimental seismic disturbances. Their use has greatly

improved geological interpretations and has led to a much higher rate of successful wildcat drilling. Future

innovation may include 4D seismic (essentially time-lapse 3D seismic), which could help improve flow models to

optimize recovery.

 Cross-well Seismic Surveys - Cross-well seismic surveys are used to evaluate the geological characteristics of

terrain between wells. Cross-well seismic measures the vibrations detected in one or more wells when widespectrum sound is produced 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 vertical to follow

the path of a gas-producing formation. While more costly than vertically completed wells, wells with horizontal

completion segments often produce at rates 3 to 5 times that of vertical wells and may reduce the unit costs of

production by as much as 50 percent. The first offshore horizontal wells were drilled in 1990 and have played an

important role in exploiting gas reserves in the Gulf of Mexico.

*The finding and lifting costs introduced here represent calculations for the major integrated oil- and gas-producing companies and the large

independent firms included in the Energy Information Administration’s Financial Reporting System (FRS). The FRS companies are 24 major U.S.

energy companies that are required to report financial and operating developments annually to the Energy Information Administration on Form EIA-28,

“Financial Reporting System,” pursuant to Section 205(h) of the Department of Energy Organization Act.
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

Technological Improvements (Continued)

 Multilateral Drilling - This drilling method involves drilling multiple horizontal well completion segments at

different depths having varying characteristics (e.g., permeability) and allows for economical recovery of a greater

portion of a given well’s reserves under certain conditions. 

 Subsalt Drilling - Considerable gas deposits are believed to reside beneath large horizontal sheets of salt. While

historically the salt sheets blurred seismic images and made it difficult to drill successfully for subsalt gas deposits,

new technologies have sharpened seismic images and improved chances of discovery. The first subsalt discovery

to be commercially developed was the 1993 Mahogany strike in 370 feet of water off the Louisiana coast.

Subsequent discoveries, including the Teak, Agate, Chimichanga, Enchilada, and Gemini wells, suggest high future

potential for offshore development of subsalt gas deposits.

 Floating Production Systems - Key to expansion of deep water gas exploration and development, floating

production systems include floating platforms or structures tethered to the sea floor. Their advantages over fixed

platforms include deeper range in offshore waters, lower average costs over their productive lives because they can

be towed to various locations, and greater tolerance of hurricanes and other inclement weather as they move

compliantly to waves. Two major types of floating systems are:

— Tension Leg Platform (TLP) - Consisting of a hull with excess buoyancy that maintains tension in a tether

mooring system, it behaves like an inverted pendulum that moves compliantly to waves. Because conventional

TLPs have encountered problems in waters over 3,000 feet, various modifications have been created for

deeper waters that include tension base TLPs, suspended TLPs, tension raft jackets (TRJs), and hybrid

compliant platforms (HCPs). The first TLP, Conoco’s Jolliet at 1,720 feet of depth, came onstream in 1989.

— Spar Production System - Consisting of a single point buoy tanker loading and mooring platform with a

storage tank, the spar’s stability is increased because its center of buoyancy is above its center of gravity. In

contrast to a TLP, the spar’s hull does not support the production risers; instead, two separate floats carry the

weight of the risers. Spar technology offers operators a way to reduce deep water production costs while still

having surface well completions. The first spar was introduced in 1997 at Oryx’s Neptune in nearly 2,000 feet

of Gulf water.

 Subsea Production Systems - Subsea production systems have found wider applications in the Gulf of Mexico over

the past 2 to 3 years as production moves into deeper water. By tying back subsea wells to either floating production

systems or platforms in shallower water, operators are able to develop wells, including smaller ones, that otherwise

would not be economic. In deeper waters, some operators are using subsea production systems based on template

and well cluster designs. The Gulf’s first subsea cluster production system was installed at Popeye Field, which

started production in 1996. In an attempt to reduce costs, subsea production systems are becoming smaller, more

modular units, and greater emphasis is being placed on retrievable subsea components.

 
1981 1984 1987 1990 1993 1996

0

5.00

10.00

15.00

20.00

25.00

1996 Dollars per BOE

Offshore

Onshore

Offshore 1995 Offshore 1996 Onshore 1995 Onshore 1996

0

2

4

6

8

10

1996 Dollars per BOE

Finding Costs

Lifting Costs

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

BOE = Barrels of oil equivalent.

Note: Finding costs are 3-year weighted averages of exploration and development expenditures for oil and gas, converted to BOE.

Source: Energy Information Administration, Performance Profiles of Major Energy Producers 1996 (January 1998) and earlier editions.

Figure 7. Finding Costs for Natural Gas and Crude Oil, 1981-1996

Figure 8. Offshore and Onshore Production Costs for Natural Gas and Crude Oil, 1995 and 1996

BOE = Barrels of oil equivalent.

Note: Finding costs are 3-year weighted averages of exploration and development expenditures for oil and gas, converted to BOE. Lifting

(or production) costs are the out-of-pocket costs of extracting oil and gas and include operating (direct lifting) costs and production taxes.

Source: Energy Information Administration, Performance Profiles of Major Energy Producers 1996 (January 1998).
0

2,000

4,000

6,000

8,000

10,000

1,720

2,864 2,958

5,327

6,530

7,500 7,620

Natural Gas Fields

Water Depth in Feet

Jolliet -

1989

Auger -

1994

Mars -

1996

Mensa -

1997

King's

Peak -

2000

Coulomb -

Planned

BAHA -

Planned 

Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

Figure 9. Depth Records in Deep Water Gulf Drilling

Note: Water depths (in feet) are noted for each project.

Source: “Seventy U.S. Gulf deepwater fields awaiting development, 26 are in production,” Offshore (September 1997), p. 39.

Canada Southward

Canadian gas is imported into four U.S. regions: the Midwest

(with a 28-percent share of the total in 1996); the Central

States (17 percent); Northeast (20 percent); and the Pacific 37

Northwest (35 percent). Expansion of Canadian pipeline

capacity 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 percent in

1990 to 84 percent in 1996. Certain corridors, especially from

Canada to the U.S. Northeast and from Canada to the U.S.

Midwest, were operating at or close to full operational

capacity in 1996 (see Chapter 3), suggesting that Canadian

gas imports may be close to maximum flow until additional

capacity can be added.

The small growth in U.S. gas imports from Canada in 1996

and 1997 (less than 1 percent) was due largely to

deliverability limitations to the TransCanada system and other

exporting systems rather than because of Canadian supply

limitations. Production capabilities in Western Canada,

especially in Alberta, exceed the amount of pipeline capacity

now existing on the system in that area (about 10.6 Bcf per

day, of which 7.1 Bcf is directed toward Eastern Canada and

the U.S. Midwest and Northeast). As a result, Canadian

shippers have been unable to reach their full potential market

to the east.

Proposals to alleviate the situation consist of at least

11 projects within Canada, which would provide an additional

0.3 Bcf per day to Canadian markets and 7.7 Bcf per day to

U.S. gas import capacity from Canada from 1998 through

2000. (About 4.5 Bcf per day of import capacity was added

from 1990 through 1997.) A number of these projects are

competing for the same markets and will not be built in all

likelihood. Even if only half of the proposed capacity is

completed by 2000 (see Appendix B), it would accommodate

the additional 2.8 Bcf per day of projected imports while

easing bottlenecks on the pipeline network.

Moreover, on December 30, 1997, the Canada-Nova Scotia

Offshore Petroleum Board approved the Sable Offshore

Energy project, which is aimed at development of six gas

fields containing an estimated 3 trillion cubic 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 affect gas deliverability to the lower 48 States

appreciably during this period. The Maritimes & Northeast

37Most of the gas imported into the Central Region goes to the Midwest. Pipeline (MNE) transportation project will bring gas from the
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 	

Nova Scotian shelf offshore Sable Island to Eastern Canada

and the United States. One other transportation project, the

Marine Line Subsea proposal, continues to be considered as

a possible alternative to move this gas to Canadian and U.S.

markets.

Implications for Downstream Markets

Expanded pipeline capacity should move more gas eastward

from the Rocky Mountain area and San Juan Basin of New

Mexico to markets in the Northeast and Midwest during the

next few years, although increased demand from within the

Central Region could absorb some of the additional gas

supplies from these two producing areas (see Chapter 4).

Even larger increases in supplies are anticipated 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 capacity increases planned from all

three sources, while increased supplies to the Northeast

should help mitigate potential increases in natural gas prices.

Increased use of storage, particularly high-deliverability salt

cavern storage, is likely to play a role in stabilizing prices by

better matching seasonal demand with available gas supplies.

In the longer term, increased gas supplies from Nova Scotia

are targeted primarily at the Northeast and Eastern Canada,

potentially contributing to further leveling of natural gas

prices throughout North America.

Summary

Natural gas production in the lower 48 States is forecast to

rise 7.8 percent from an average of 50.1 billion cubic feet per

day in 1996 to 54.0 billion cubic feet per day in 2000, with

much of the increase coming from the offshore Gulf of

Mexico, the Permian Basin, and the Rocky Mountain area. A

technological revolution during the 1990s, led by 3-D seismic

surveys, horizontal drilling, and new offshore platform

designs, has opened up deeper water frontiers in the Gulf of

Mexico while also yielding new opportunities in onshore

producing regions. Additional pipeline capacity from

producing areas in Western Canada to major markets in the

U.S. Northeast and Midwest will allow natural gas imports

from Canada to rise, contributing to increased U.S. gas

supplies in the near term.

Planned pipeline expansions through 2000 appear generally

adequate to accommodate new lower 48 productive capacity

and increased Canadian gas imports, although bottlenecks

may be caused by lack of sufficient capacity to carry

anticipated new offshore gas production beyond onshore

Louisiana and the fact that most of the pipeline expansions

allowing for increased Canadian imports are not due for

completion before 1999 and 2000.

Major expansions of underground storage underway in the

Northeast and Midwest as well as along the Texas and

Louisiana coasts could help to avoid bottlenecks for gas

moving northward from the offshore and onshore Gulf and

ensure adequate deliverability to the top U.S. gas markets.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

3. Deliverability on the Interstate Network

The United States has a complex, extensive pipeline infra- national pipeline grid, allowing the system to operate in a

structure for transporting natural gas from production areas to much smoother manner.

ultimate consumers. More than 85 U.S. interstate pipeline

companies operate almost 200,000 miles of transmission Although a few natural gas transportation corridors are

lines, hundreds of compressor stations, and numerous storage operating at close to full utilization year round, the pipeline

facilities, allowing gas delivery throughout the lower network in North America has demonstrated its capability to

48 States. The importance of the network is reflected in the meet the current level of demand. In addition, several

fact that 27 of the lower 48 States are almost totally expansions are planned to alleviate those cases where

dependent upon the interstate system for their gas supplies limitations exist, especially along those corridors transporting

(Appendix C, Table C2). Canadian gas into the United States. In fact some excess

Fifty of the interstate pipeline companies are classified as probably will be some local areas where available pipeline

“major” systems by the Federal Energy Regulatory capacity will not match demand.

Commission (FERC), in that they each transported more than

50 million dekatherms (equivalent to about 66 billion cubic

feet (Bcf)) of natural gas in each of the past 3 years. During

January 1996, the month of greatest gas consumption that

year, deliveries to end-use customers averaged 77 Bcf per

day, with much of the gas moving along these same

pipelines. The smaller interstate pipeline companies and the 38

intrastate network (more than 200 systems) are also

important, although their services are regional in nature. In

fact, some of the intrastate pipeline systems in Texas and

Louisiana rival some of the interstate systems in capacity,

volumes transported, and revenue generation.

This chapter examines the capability of the interstate pipeline

system to link production and market areas, focusing on

pipeline operations along 10 distinct corridors: 5 of which

extend from the Southwest, 3 from Canada, and 2 from the

Rocky Mountains. It identifies the various pipeline companies

operating in each corridor and discusses the changes in

capacity and usage that have occurred since 1990. It also

briefly describes how some of the changes that have occurred

as a result of industry restructuring have affected the way gas

moves along the pipeline network.

The natural gas pipeline network has grown substantially

since 1990, with more than 11.4 Bcf per day of interregional

capacity (a 15-percent increase) added through the end of

1997. Meanwhile, the network has become more

interconnected, its routings more complex, and its business

operations more fluid. New types of facilities, such as market

centers, and established operations, such as underground

storage facilities, have become further interwoven into the

capacity could develop along several corridors, although there

Recent Changes Affecting the

 Pipeline Network

Pipeline system operations have changed radically during the

past 10 years, particularly since 1992 when FERC issued

Order 636. The order formalized the transition of interstate

pipeline companies from sellers of natural gas to

nondiscriminatory transporters and mandated open access to

interstate storage facilities. The resulting restructuring of the

industry changed how network resources were being used and

caused some shifts in transportation routes and trading and

shipping arrangements. 

 The increased competitiveness of the marketplace has

led to several new pipeline interconnections as end

users sought access to the least expensive gas supplies.

With pipeline companies no longer owning the gas they

transport, end users became responsible for making their

own arrangements for purchasing and transporting

natural gas. Sometimes the traditional pipeline link could

not accommodate the consumers’ needs directly and

consequently several new transportation relationships

(interconnections) developed.

 Storage has become an increasingly important

component of overall pipeline and network

operations. The interstate pipeline network depends

upon a large number of underground storage sites to

provide storage services to pipeline shippers and as a

means for maintaining system balances and backup.

Underground storage provides the mechanism through

which a pipeline company can maintain control over its

throughput levels in an environment where it no longer

has total control over its receipts and deliveries. Of the

410 underground storage sites operating in the United

Based on total gas delivered to residential, commercial, industrial and 38

electric utility customers in the United States. Energy Information

Administration, Natural Gas Monthly, DOE/EIA-0130(97/12) (Washington,

DC, December 1997).
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

States in 1996, almost half (190), representing more than trading at strategic points throughout the North American

52 billion cubic feet of peak-day deliverability, were pipeline grid. Most of the points are located in production

owned by interstate pipeline companies or their areas, reflecting the selling of gas by producers at various

affiliates. Another 39 of the 400 storage sites serve the gathering and pooling points. However, the number of 39

interstate market although they are owned by points within market areas is growing as shippers

independent operators or large local natural gas demand more trading flexibility to handle imbalance

distribution companies. The majority of sites owned by situations during peak transportation periods. Currently,

independent operators are linked to natural gas market there are almost 150 trading points defined on these

centers. electronic trading services. In addition, many of these

 Market centers have proliferated during the 1990s trade press. For instance, Gas Daily, a widely circulated

and are becoming increasingly integrated into industry newsletter, publishes a daily price index of

the transportation network. Natural gas market centers natural gas trades based upon transactions reported at

are a recent development in North America. Prior to approximately 120 points in North America.

1990, only the Henry Hub site in southern Louisiana

loosely fit the current profile of a market center. Today, Market centers and electronic trading centers/points are 40

at least 38 market centers are operating in the United rapidly becoming vital components in maintaining an efficient

States and Canada, providing numerous interconnections and smooth pipeline network operation in North America.

and routes to enhance transfers and movements of gas The vast majority of market and trading centers are located at

from production areas to markets. These centers provide either end of most of the transportation corridors discussed in

a number of services formerly provided by pipeline the following sections. Future growth, or lack thereof, within

companies and also offer many of the new services these corridors will become a function of how much activity

needed in today’s market, such as short-term gas loans or develops at these sites. Conversely, growth in demand within

temporary gas parking. The types of flexibility demanded individual corridors would be necessary to support any

of market center services is predicated upon the use of additional market and trading centers.

high-deliverability (mostly salt cavern) underground

storage facilities. Practically all of the high-deliverability

storage located in North America is accessible through or

linked directly to market centers. More than two-thirds of

market centers have some form of storage access,

accounting for about 47 percent of the working gas in

North America, or more than 2 trillion cubic feet. Market

centers also offer transportation (wheeling) services,

balancing, title transfer, gas trading, electronic trading,

and administrative services needed to complete

transactions on behalf of the parties.

 The emergence of natural gas trading centers or

trading points is also a recent development within the

natural gas marketplace. Trading centers, which

sometimes represent the same physical points as a market

center or hub, have emerged with the growth of

electronic gas trading. Many centers also represent

trading points that evolved from the natural gas spot

market that first arose during the mid-1980's. At first,

commercial electronic gas trading systems were

associated with and available only through a few market

centers, but now their marketability has been expanded

as subscribers are being offered the opportunity to enact

41

same points, and some others, are tracked in the industry

System Growth Since 1990

The accommodations to change in the restructured industry

brought about significant shifts in natural gas receipt,

transport, and deliverability along the pipeline network. Since

1990, several new pipelines have been constructed that have

improved customer access to production sources (Figure 10).

But, for the most part, much of the new capacity added on the

network was an expansion to existing systems in order to

increase access to new production sources or to new markets.

Between 1990 and the end of 1997, capacity additions on the

long-haul corridors alone, which link production and market

areas, totaled approximately 12.4 billion cubic feet per day,

an increase of about 17 percent. Capacity and deliverability 42

additions made during the period fall into several categories:

Energy Information Administration, Form EIA-191, “Underground Gas area point, NGPL Texas/Oklahoma. 39

Storage Report.” Energy Information Administration, EIAGIS-NG Geographic

Energy Information Administration, Natural Gas 1996: Issues and Information System, Natural Gas Pipeline State Border Capacity, as of 40

Trends, DOE/EIA-0560(96) (Washington, DC, December 1996), Chapter 3. December 1997.

In fact, according to Quicktrade L.L.C., one of the largest of the 41

electronic trading companies in volume traded, the Chicago trading point, in

1996 transacted six times more business than the largest traded production

42
(600)

 Bluewater Pipeline 1995

(250 Bi-directional)

Discovery Pipeline 1997

(600)

(600)

(200)

Empire Pipeline 1994

(500)

Manta Ray Gathering System 1997

(300)

Garden Banks Offshore System 1997 DIGS Main Pass Gathering System 1997

Mobile Bay Pipeline 1993

(850)

Iroquois Pipeline 1991

(750)

(110)

Tuscarora Pipeline 1995

(450)

Mojave Pipeline 1992

TransColorado Pipeline 1996

(Southern Leg)

(120)

(255)

Pony Express Pipeline 1997 (250)

Crossroads Pipeline 1995

(600)

Nautilus Pipeline 1997

Kern River

Pipeline 1992

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

Figure 10. Capacity of New Natural Gas Pipeline Systems Placed in Service in the United States Between

1990 and 1997

(Volumes in Million Cubic Feet per Day)

Note: Crossroads and Pony Express pipelines were conversions of existing oil pipelines to natural gas usage.

Source: Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity and

Natural Gas Proposed Pipeline Construction Database, as of December 1997.

 New pipeline systems built either to transport gas from capacity was brought into service. In 1994, 1995, and 1996,

expanding production areas or to service new market new capacity additions fell off dramatically (totaling only

areas 4.9 Bcf per day over the 3 years). The low level of pipeline

 Expansion of existing systems to accommodate growing as 1992 and earlier, just as the natural gas marketplace was

customer demand but accessing supplies already linked undergoing a major restructuring and expanding deregulation.

to the network Uncertainty about the needs of this new market most likely

 Expansion of an existing system to accommodate shipper addition, as market conditions changed so did some project

supplies transported via other pipeline systems plans.

 Expansions of short-haul local delivery lines to link with In 1997, more than 40 pipeline projects were completed, the

new customers who bypass local natural gas distribution largest number since 1993, adding 6.3 Bcf per day of capacity

companies overall while adding 0.5 Bcf per day to interregional

 Expansions of pipeline systems in areas where productive major portion of the new pipeline capacity represented

capacity was greater than existing transportation increased receipt capability in expanding supply areas. For

capacity. instance, the largest projects were in the Gulf of Mexico

Most of the pipeline expansions since 1990 took place efforts in the area continue to expand. In addition, several

between 1991 and 1993, when approximately 17.2 billion

cubic feet (Bcf) per day of additional interstate pipeline

43

expansions in those years reflects decisions made as far back

kept the number of proposed projects to a minimum. In

deliverability and 3.9 Bcf to intraregional deliverability. A

(3.2 Bcf per day) as offshore and deep-water development

The total capacity represented by the major interstate pipeline 43

construction projects during the period tabulated on a per project basis.
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

major projects were completed that expanded access to the routes extend from the producing areas of the Southwest,

Wind River and Powder River basins of the Rocky Mountain three routes enter the United States from Canada, and two

area by more than 0.5 Bcf per day. The first new export lines originate in the Rocky Mountains. For this analysis the

to Mexico to be completed in 5 years were also placed in 10 corridors have been roughly delineated as follows

service during 1997. (Figure 12):

The greatest increase in capacity since 1990 occurred on those

routes between Canada and the U.S. Northeast, 1.9 Bcf per

day, or 412 percent (Table 7). This was brought about with  Southwest–Southeast: from the area of East Texas,

the completion of several new pipelines and expansions to Louisiana, Gulf of Mexico, and Mississippi to the

several import stations, almost exclusively in New York State Southeastern States.

(Figure 11). The largest increase in domestic capacity was

between the Southwestern and Southeastern States, 1.0 Bcf Southwest–Northeast: from the area of East Texas,

per day. This increase was driven primarily by the growth in Louisiana, Gulf of Mexico, and Mississippi to the U.S.

electric power and industrial demand for natural gas in the Northeast (via the Southeast Region).

Southeast, particularly in Florida.44

The magnitude of pipeline expansion since 1990 can best be Louisiana, Gulf of Mexico, and Arkansas to the

illustrated in conjunction with the natural gas pipeline Midwest.

transportation patterns that have emerged in North America

over the years (Figure 12). In the early 1990s, three  Southwest Panhandle–Midwest: from the area of

geographic regions were the primary focus of capacity southwestern Texas, the Texas and Oklahoma

expansion: the Western, Midwest, and Northeast regions. All panhandles, western Arkansas, and southwestern

three regions shared one common element, greater access 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

production sources were developed in the San Juan Basin of Texas (Permian Basin) and northern New Mexico

New Mexico and demand for natural gas in California was (San Juan Basin) to the Western States, primarily

expected to grow substantially during the decade. California.

Through the year 2000, U.S. access to Canadian production

is expected to continue to expand at a rate never before seen,

while major service 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 capabilities

from the Rocky Mountain, New Mexico, and West Texas  Canada–Northeast: from the area of Western Canada

areas eastward to link with pipeline systems reaching the to Northeastern markets in the United States.

Midwest and Northeast markets. With the completion of this

effort, the interstate natural gas pipeline network will come  Canada–Western: from the area of Western Canada

closer to being a national grid where production from almost to Western markets in the United States.

any part of the country can find a route to customers in almost

any area. It will fill the gap in the national network that to

some extent has left the Rocky Mountain and Western natural

gas producers isolated from certain markets (see Chapter 2).  Rocky Mountains–Western: From the Rocky

Major Transportation Corridors

The national natural gas delivery network is quite intricate

and expansive, but most of the major transportation routes can

be broadly categorized into 10 distinct corridors. Five major

From the Southwest

	 Southwest–Midwest: from the area of East Texas,

From Canada

From the Rocky Mountains

Mountain area of Utah, Colorado, and Wyoming to

the Western States, primarily Nevada and California

with support for markets in Oregon and Washington.


 Rocky Mountains–Midwest: From the Rocky

Mountain area to the Midwest, including markets in

Iowa, Missouri, and eastern Kansas.

Only a small part of this additional capacity, 342 MMcf per day, 44

represented capacity that continued on to the Northeast or Midwest regions.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

Table 7. Interregional Pipeline Export Capacity, Average Daily Flows, and Usage Rates, 1990 and 1996

Sending Receiving (MMcf per Day) (MMcf per Day) (percent)

Region Region

Capacity Average Flow Usage Rate1

1990 1996 Change 1990 1996 Change 1990 1996 Change

Percent Percent

Canada Central 1,254 1,563 25 941 1,542 64 75 99 24

Midwest 2,161 3,049 41 1,733 2,581 49 84 85 1

Northeast 467 2,393 412 309 1,834 494 66 77 11

Western 2,421 3,786 56 1,874 3,275 75 78 87 10

Total from Region 6,303 10,791 69 4,857 9,233 90 78 86 8

Mexico Southwest 350 350 0 0 37 -- 0 11 --

Total from Region 350 350 0 0 37 -- 0 11 --

Central Canada 66 66 0 44 4 -99 67 4 -63

Midwest 8,988 9,879 10 5,684 7,714 36 63 78 15

Southwest 1,283 2,114 64 572 1,267 122 68 70 2

Western 365 1,194 227 196 713 264 54 95 41

Total from Region 10,702 13,253 24 6,495 9,698 49 63 78 15

Midwest Canada 1,211 2,543 110 961 1,626 69 79 68 -11

Central 1,765 2,354 33 974 1,564 61 86 94 8

Northeast 4,584 4,887 7 3,474 4,220 21 76 86 11

Total from Region 7,560 9,784 29 5,409 7,410 37 78 83 5

Northeast Midwest 2,024 2,038 1 714 910 27 45 45 0

Southeast 100 520 417 63 15 -78 63 60 -3

Total from Region 2,124 2,558 20 777 925 18 46 45 -1

Southeast Midwest 9,645 9,821 2 6,134 8,020 31 64 82 18

Northeast 4,971 5,149 4 4,091 4,431 8 82 86 4

Southwest 405 405 0 75 60 -20 79 86 -4

Total from Region 15,021 15,375 2 10,300 12,511 22 70 83 13

Southwest Central 8,555 8,609 1 4,119 4,993 21 49 60 11

Mexico 354 844 138 38 83 117 11 10 -1

Southeast 19,801 20,846 5 14,613 16,063 10 74 77 3

Western 4,340 5,351 23 3,910 2,415 -38 90 45 -45

Total from Region 33,050 35,650 8 22,680 23,555 4 69 66 -3

Western Central 250 298 19 196 4 -- 78 0 --

Mexico 45 45 0 5 9 86 11 21 9

Total from Region 295 343 16 201 13 -93 69 29 -40

Usage rate shown may not equal the average daily flows divided by capacity because in some cases no throughput volumes were reported 1

for known border crossings. This capacity was not included in the computation of usage rate. 

MMcf = Million cubic feet. -- = Not applicable.

Sources: Energy Information Administration (EIA). Pipeline Capacity: EIAGIS-NG Geographic Information System, Natural Gas Pipeline

State Border Capacity Database, as of December 1997. Average Flow: Form EIA-176, “Annual Report of Natural and Supplemental Gas Supply

and Disposition.” Usage Rate: Office of Oil and Gas, derived from Pipeline Capacity and Average Flow.
Western

NN = 1996

(NN) = 1990

N% = Percent Change

 844

(354)

138%

Central

Southwest

M idw est

Southeast

Northeast

 350

(350)

0 %

 45

(45)

0 %

 298

(250)

19%

 3,786

(2,421)

45%

 20,846

(19,801)

5 %

 8,609

(8,555)

1 %

 5,351

(4,340)

23%

405

(405)

0 %

 5,149

(4,971)

4 %

 9,821

(9,645)

2 %

 520

(100)

418%

 2,038

(2,024)

1 %

 3,049

(2,161)

41%

 2,393

(467) 2,543 412%

(1,211)

110%

 4,887

(4,584)

7 %

 2,354

(1,765)

33%

 9,879

(8,988)

9 %

 1,194

(365)

227%

 1,563

(1,254)

25%

 2,114

(1,283)

64%

 66

(66)

0 %

6,000

9,000

12,000

15,000

 0

3,000

 Capacity 

(Million Cubic Feet per Day (MMcf/d))

N = Corridor ID

= Less than 100 MMcf/d Capacity

8

10

5

9

4

6

2

3 1

7

Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

Figure 12. Major Natural Gas Transportation Corridors in the United States and Canada, 1997

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity

Database, as of December 1997.

Figure 11. Region-to-Region Natural Gas Pipeline Capacity, 1990 and 1996

(Volumes in Million Cubic Feet per Day)

Note: The 10 transportation corridors 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) Rocky Mountains–Western,

and (10) Rocky Mountains–Midwest. 

Source: Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity Database,

as of December 1997.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

While these 10 corridors constitute the bulk of the long- a lesser degree, this is also true for the pipeline capacity

distance transportation routes, a number of regional pipeline exiting to the midsection of the country, much of which is

systems also serve markets within either the supply region ultimately destined for the Midwestern States.

itself or the major market areas. For instance, one of the

largest pipeline systems within the Southwest supply region The Southwestern States also have a large number of

is NORAM Gas Transmission Company; within the Northeast underground storage facilities, most of which were once used

market region, Columbia Gas Transmission Company is a to store excess natural gas production during months of low

major interstate transporter/distributor of natural gas (see consumption. While still true, production storage service is

Chapter 4 for a regional breakout of pipeline service areas). now only one of the functions provided by these sites. A

Originating Regions 

The largest amount of natural gas pipeline capacity exists on

those systems that link the production areas of the U.S.

Southwest with the other regions of the country. Capacity

exiting the region in 1996 was nearly 36 billion cubic feet

(Bcf) per day. Between 1990 and the end of 1996, total export

capacity from the region grew by 8 percent or 2.6 Bcf per day

(Table 7). Export capacity from the Central Region, which

includes the Rocky Mountain production areas, was slightly

more than 13.3 Bcf per day in 1996, most of which is directed

to the U.S. Midwest (9.9 Bcf per day). About 86 percent of

this latter figure, however, represents capacity that originates

outside the region (from the Southwestern States or at the

Canadian border) and merely traverses the region. Canadian

export capacity into the United States in 1996 stood at about

10.8 Bcf per day. That figure represents a growth of

69 percent (4.5 Bcf per day) since 1990, with much of the

additional export capacity reaching into the U.S. Northeast.

The motivation behind many of the expansion projects

completed in these exporting regions from 1991 through 1996

was to improve deliverability from capacity-constrained

production areas and/or provide alternative routing opportunities to shippers seeking access 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 Mexico. This area of the country exports

about 60 percent (8.6 trillion cubic feet in 1996) of its

production, which is 58 percent of the total natural gas

consumed elsewhere in the lower 48 States. Pipelines exiting 45

the region have the capacity to accommodate as much as

35.7 Bcf per day: 58 percent to the Southeast Region,

24 percent to the Central Region, 15 percent to the Western

Region, and the rest to Mexico (Figure 11). Much of the

pipeline capacity directed toward the Southeast traverses the

region en route to Midwestern and Northeastern markets. To

46

growing amount of the storage in the region is highdeliverability (salt dome) storage, which allows a rapid

drawdown of inventory (within 10 days or once a month) and

quick shifts from injection to withdrawal mode. This type of

storage is highly complementary of the needs of shippers,

who under today’s rules must manage their own accounts and

avoid costly pipeline imbalance penalties and the other

vagaries of a more competitive marketplace. Total working

gas storage capacity in the Southwest (over 982 billion cubic

feet) is the second highest of the six regions (Appendix C,

Table C1).

In the Central Region, only one major interstate pipeline

provides transportation services directly 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 interconnections these lines have with the interstate

pipelines traversing the region, principally those coming out

of the Southwest Region.

Transportation Corridors

 Southwest-Southeast

Two routes extend from the Southwest to the Southeast

Two fairly distinct subcorridors extend into the Southeast

Region from the Southwest: one goes eastward into

Mississippi and continues further east, and the second goes

northward into Tennessee and Kentucky (Figure 12). Along

the first route, there are three major interstate pipeline

companies that operate almost exclusively within the

Southeast Region—Florida Gas Transmission Company

(FGT), Koch Gateway Pipeline Company (Koch), and

Southern Natural Gas Company (SONAT) (Table 8).

Together they can handle at least 4.9 billion cubic feet (Bcf)

per day for shippers in the region.

For purposes of this discussion, exports pertain to all volumes leaving a Natural Gas in 1997: Existing and Proposed,” Natural Gas Monthly, 45

region for another region or country. DOE/EIA-0130(97/09) (Washington, DC, September 1997).

Energy Information Administration, “U.S. Underground Storage of 46
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

Table 8. Natural Gas Transportation Corridors and Associated Major Pipeline Systems, 1996

Corridor / Pipeline Name Crossed Points Points Rate Wide Point

Other Number of Number of Average Day Capacity

Regions Delivery Interconnect Utilization (MMcf/d) 1 12 3

 1 - Southwest-Southeast

Florida Gas Transmission Co None 181 3 71 1,475

Koch Gateway Pipeline Co None 33 44 40 1,134

Southern Natural Gas Co None 323 10 67 2,250

Texas Gas Transmission Corp None 215 8 81 2,163

Transcontinental Gas Pipeline Co None 121 10 84 3,467

 2 - Southwest-Northeast

Columbia Gulf Transmission Co Southeast 0 4 87 2,063

Tennessee Gas Pipeline Co Southeast 116 61 90 2,671

Texas Eastern Transmission Corp Southeast 69 23 84 2,850

Transcontinental Gas Pipeline Co Southeast 124 16 83 2,587

 3 - Southwest-Midwest

ANR Pipeline Co Southeast 259 18 70 2,013

Midwestern Gas Transmission Co Southeast 18 10 59 665

Natural Gas Pipeline Co of America Central 165 9 61 1,893

Texas Gas Transmission Corp Southeast 102 20 79 1,509

Texas Eastern Transmission Corp Southeast 50 13 84 324

Trunkline Gas Co Southeast 53 8 74 1,853

 4 - Southwest Panhandle-Midwest

ANR Pipeline Co Central 259 18 70 853

Natural Gas Pipeline Co of America Central 165 8 61 1,765

Northern Natural Gas Co Central 129 4 45 2,500

Panhandle Eastern Pipeline Co Central 67 6 78 1,573

 5 - Southwest-Western

El Paso Natural Gas Co None 339 2 51 4,261

Transwestern Gas Pipeline Co None 6 1 36 1,225

 6 - Canada-Midwest

Foothills Pipeline Co LTD (Canada) None 0 1 NA 1,675

Great Lakes Gas Transmission Co (U.S.) None 206 30 88 2,286

Northern Border Pipeline Co (U.S.) Central 2 2 102 1,675

TransCanada Pipeline LTD (Canada) None 0 2 NA 7,100

Viking Gas Transmission Co (U.S.) None 42 7 45 425

 7 - Canada-Northeast

Empire Pipeline Co (U.S.) None NA NA NA 500

Granite State Gas Transmission Co (U.S.) None NA NA 52 62

Iroquois Gas Pipeline Co (U.S.) None 10 8 90 858

Tennessee Gas Pipeline Co (U.S.) None 31 25 90 843

TransCanada Pipeline LTD (Canada) None 4 3 NA 3,950

 8 - 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 282 4 56 1,289

Pacific Gas Transmission Co (U.S.) None 190 2 93 2,454

Tuscarora Gas Transmission Co. (U.S.) None 5 1 NA 110

Westcoast Gas Transmission LTD None 1 1 NA 1,066

 9 - Rocky Mountains-Western

Kern River Gas Transmission Co None 30 1 95 750

10 - Rocky Mountains-Midwest

Trailblazer Pipeline System None 0 4 127 411

KN Interstate Gas Co None 0 12 32 120

Williams Natural Gas Co None 0 24 47 186

Represents the number of delivery points or major pipeline interconnections along the section(s) of the pipeline systems associated with and 1

within the respective corridor.

Based on the sum of the State crossing point capacities of the respective pipeline divided by the sum of average daily flows at the same points. 2

Represents the capacity (throughput capability) of the pipeline system at its maximum within the corridor. 3

NA = Not available. MMcf/d = Million cubic feet per day.

Sources: Federal Energy Regulatory Commission, FERC 567 Capacity Report, “System Flow Diagram.” Energy Information Administration

(EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity Database, as of December 1997.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 	

Varying amounts of capacity on several other large interstate coincided with the 655 MMcf per day expansion of the FGT

pipelines that follow this subcorridor also serve limited system and the multi-phased expansion on the southern

markets in the region. For instance, Transcontinental Gas portion of the Transco system, totaling 220 MMcf per day.

Pipeline Company (Transco) serves customers in Georgia,

South Carolina, and North Carolina as it continues along its FGT expanded its system to provide additional service to the

route up the east coast (Appendix A, Figure A4). However, State’s electric power generation sector and to a growing

this service only represents about 1.1 Bcf per day, or industrial sector; natural gas use in these sectors grew at an

30 percent, of the 3.5 Bcf per day found on the Transco annual rate of 9.8 and 8.7 percent, respectively, between 1990

system as it enters the region. Yet, in North Carolina it is and 1996. Capacity utilization on the FGT system on its peak

essentially the only source of natural gas supplies to the State. day in 1995 was 102 percent (Figure 17, Chapter 4). During

Along the second subcorridor, one pipeline company was 97 percent, while during its lowest month (February) it

predominates, at least in terms of delivery points, Texas Gas fell to only 66 percent. FGT is unique in that its highest usage

Transmission Company (TGT). While this system extends rates occur during the summer months, reflecting the strong

into the Midwest Region, more than 70 percent of its delivery electric generation (for air conditioning) needs within this

points are located in the States of Kentucky and Tennessee. warm region.

TGT provides substantial deliveries to underground storage

facilities in northern Kentucky that supplement supplies to the Tennessee Gas Pipeline Company (Tenneco) added capacity

local market and to the Midwest Region during the heating within this corridor to improve its overall capability to serve

season. customers in the Northeast. While its several mainlines were

Tennessee Gas Pipeline Company (Tenneco) and Texas sizeable percentage increase to overall capacity along the

Eastern Transmission Company (TETCO) are two additional corridor. Tenneco increased its capacity on the route by

systems operating along this subcorridor, but most of their 19 percent (126 MMcf per day) leaving the production area

delivery points are outside the Southeast Region. Tenneco, of the Southwest (Appendix A, Table A4).

however, is the principal 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 corridor in 1995 ranged between 40 and 84 percent. The most

in northern Alabama, and the East Tennessee Gas Company highly utilized was the FGT system, which had a 66-percent

(Tennessee and Virginia). Nevertheless, these deliveries usage rate during the off-peak periods and close to full

represent only about 0.6 Bcf (peak-day) out of a total 2.3 Bcf capacity during its peak service period. The Transco system

deliverability available per day on the Tenneco system. operated at about 83 percent on average, while during its peak

Capacity along the eastern subcorridor increased by about the summer off-peak period (see Chapter 4). 

5 percent between 1991 and 1996, primarily because of a

substantial expansion on a major part of the Florida Gas The underground storage facilities located along this corridor

Transmission system (up to 80 percent). In addition, while the are defined by their location. Those facilities at the corridor’s

Transcontinental 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 directed toward service along this corridor rather shippers and traders who want to acquire supplies for

than on its Northeast regional section. Transco’s expansion shipment to market (Appendix C, Table C1). Of the 9.3 Bcf

during the period included a large capacity addition (0.4 Bcf of daily storage deliverability (withdrawal) available in the

per day) to new customers in northern North Carolina. The area, 46 percent is from salt cavern sites. This feature

addition actually brought service southward, out of Virginia, provides shippers using these corridors access to very flexible

from Transco’s northbound mainline. storage, which can be used to enhance their deliverability

One new pipeline, the Mobile Bay Pipeline system gas trading or hedging activities they may wish to engage in.

(600 million cubic feet (MMcf) per day), was added within

this corridor in 1993. It was only the second pipeline built in In northwestern Kentucky, along the western subcorridor,

the Gulf of Mexico that terminates in the Southeast Region storage facilities are devoted primarily to providing seasonal

(the first being the Chandeleur Pipeline, 275 MMcf per day). supplies. They are supported, for the most part, by deliveries

The system interconnects with both the Transcontinental Gas from the Texas Gas Transmission system. The majority of the

Pipeline (Transco) and Florida Gas Transmission (FGT) storage in Mississippi and Alabama is available to shippers

systems located in Alabama. The completion of this pipeline using either subcorridor.

its month of greatest throughput (July), average utilization

already quite large in 1990, the added capacity represented a

periods operated at about 99 percent and 81 percent during

schedule, avoid transportation imbalances, and support any
Energy Information Administration


 Deliverability on the Interstate Natural Gas Pipeline System

The principal pipeline expansions proposed along, or within, increase was on the Tennessee Gas Pipeline system, which

this corridor through 2000 represent greater access to Gulf of rose from 80 to 86 percent.

Mexico supplies and improvements to service within the

Southeast Region (Appendix B, Table B2). Projects slated to During wintertime peak periods, each of the systems are

provide new or improved access to Gulf of Mexico supplies almost fully utilized. During the summer months, however,

amount to about 1.7 Bcf per day or 54 percent of the regional usage rates for the pipeline systems operating along this

projects currently proposed. Strictly onshore, the SONAT corridor tend to drop substantially. Except for the Columbia

system will add 141 MMcf per day to its northern section, Gulf Transmission system, which operated at close to

while Transco will upgrade its system with a short-haul 100 percent year-round during 1995, the summertime (system

400 MMcf per day pipeline link to a new liquefied natural gas wide) usage rates ranged from 49 percent for Texas Eastern’s

facility in North Carolina. In addition, Transco plans to system to 81 percent for Transco’s system. The principal

update its facilities along this route to support the factor affecting 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 MMcf 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 MMcf per day). past several years, the refill rate and level of total (storage)

Southwest-Northeast

The main flow of U.S. gas is toward the Northeast

The Southwest-to-Northeast corridor consists of two routes.

The first extends from East Texas and Louisiana

northeastward through Mississippi, Tennessee, Kentucky, and

parts of Ohio to enter the Northeast Region via West Virginia

or Pennsylvania (Figure 12). The second route begins as the

first but then extends northeastward from Mississippi via the

east coast States and enters Virginia from the south. 

The principal interstate pipeline systems operating along the

corridor include Tennessee Gas, Columbia Gulf

Transmission, and Texas Eastern Transmission on the western

segment, and Transcontinental Gas Pipeline on the eastern

segment. These four pipeline companies represent

approximately 9.3 Bcf per day of total capacity, making this

corridor the largest of the major transportation corridors in

North America.

Since 1990, capacity on this corridor increased only slightly,

about 500 MMcf per day. Most of that, 300 MMcf per day,

occurred on the Texas Eastern Transmission system as

improvements were made to the links between its eastern

seaboard network and its Midwest interconnections.

Transcontinental Gas Pipeline system increased its capacity

by 310 MMcf per day, but little of this expansion affected its

system north of Virginia.

The average utilization rates for the pipelines operating along

this corridor ranged from 73 to 86 percent in 1996, for an

overall average rate of 82 percent (Appendix A). That overall

rate was the same as in 1990. With the exception of

Transcontinental Gas Pipeline system, which had a slight drop

in utilization between the two comparison years, usage on

each of the pipeline systems increased marginally. The largest

working gas inventory prior to the heating season has fallen

as inventory management practices have changed. This trend

is reflected in the lower off-peak usage rates on some of the

affected pipeline systems.

The majority of the more than 190 underground storage sites

located along this corridor are accessible to shippers. At the

southwestern terminus of the corridor, more than 30 sites with

a working gas capacity of at least 624 billion cubic feet and a

daily withdrawal capability of 13 Bcf per day are located

within 20 miles of the subject pipeline systems. Most of this

capacity is used by producers, who use it to store short-term

excess production, and by market centers.

Most of the same Southwestern market centers and associated

storage discussed previously are also used by shippers on this

corridor. But, in addition, this corridor links with some of 47

the most active market centers located outside the

Southwestern production area. One of the most significant is

the Ellisburg-Leidy center in Pennsylvania, which provides

interconnections and transportation services between the

pipelines comprising this corridor and the other major

interstate pipelines operating primarily within the Northeast

States. Shippers using the corridor may also utilize the

services of the CNG/Sabine, Columbia Gas, and New York

(Brooklyn Union Gas Company) market centers to expand

their marketing and transportation options further. 

Several expansions have been proposed that could affect the

northwestern portion of this corridor, although they would

originate in other areas. For the most part they focus upon

expansions that could tranship some of the vast amount of

proposed new Canadian import capacity slated for the

Midwest to the Northeast Region (Appendix B, Table B2).

For instance, ANR Pipeline Company and Transcontinental

Storage capacity within each of the 10 corridors should not be summed 47

to get a U.S. total because it would result in double counting.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

Gas Pipeline Company have proposed the jointly owned Company (TGT), Texas Eastern Transmission Company

Independence project, which could carry 1 Bcf per day from (TETCO), and Trunkline Gas Company.

ANR’s line in northwestern Ohio to a major interconnection

with Transcontinental’s line in Leidy, Pennsylvania. The new These systems represent approximately 7.3 Bcf per day, or

line would also be attractive to Canadian shippers seeking an 29 percent of the total pipeline capacity feeding into the

alternative route to Northeast markets. It could also provide Midwest Region (24.8 Bcf per day). They also account for

an alternative route and opportunity for shippers now moving more than 30 percent of the total pipeline capacity exiting this

gas from the Southwestern to the Midwestern areas of the area of the Southwest.

country to reach customers in the Northeast.

Other projects that would affect this portion of the corridor development between 1991 and 1996, in large part to provide

and direct some of the new Midwestern pipeline supplies shippers on this corridor greater access to supplies from the

eastward include Tennessee Gas Pipeline Company’s Arkoma Basin in Arkansas/Oklahoma to the Northeast and

proposed Eastern Express project and Duke Energy Midwest markets, were not built. Part of the reason may have

Corporation’s Spectrum project. These two projects alone been the competing plans for Canadian import expansions and

represent a total of 1.2 Bcf per day of new capacity into the the low utilization rates on the existing lines extending to the

Northeastern United States. Midwest Region.

The Spectrum project (0.5 Bcf per day) would extend from Very little underground storage is located along the

the Chicago, Illinois, area to New York and New England, midsection of this corridor. However, shippers have access to

mostly by using expanded facilities along Duke Energy’s significant amounts of storage at either end. This corridor also

affiliated pipelines: Panhandle Eastern, Texas Eastern, and links together two major gas trading centers: the Henry Hub

Algonquin Gas Transmission systems (west to east). In in Louisiana and the Chicago Center in northern Illinois. In

addition, an interconnection with another affiliate, Trunkline addition, the corridor also includes several natural gas trading

Gas Company, could be upgraded to improve gas (and price discovery) locations accessible to shippers and

supply transshipments from the Southwest Region, if traders via the several major commercial electronic trading

appropriate (as could the Panhandle Eastern Pipeline system). systems set up in the United States and Canada. During the

The Eastern Express project (0.7 Bcf per day) would utilize heating season, these markets are actively used by shippers

Midwestern Gas Transmission Company (an affiliate of and other market participants as a way to balance their

Tennessee Gas Pipeline Company) to ship supplies southward receipts/deliveries, for arbitrage between the two markets, and

(or though exchanges of gas) to Tennessee Gas’s to smooth market and price fluctuations through hedging.

interconnection in northern Tennessee and then, through

expanded facilities on its existing system, transport supplies Pipeline utilization rates on the corridor during peak periods

from the Midwest to the east coast. of the heating season are generally in the 90 to 100 percent 48

 Southwest-Midwest

Corridor has significant off-peak capacity

The Southwest-to-Midwest corridor extends northward out of

East Texas, Louisiana, and Arkansas (Arkoma Basin

production) and generally through Tennessee/Kentucky into

the Midwest Region, although a part of it also travels through

Missouri (Figure 12). The principal interstate pipeline systems

operating along this corridor are: ANR Pipeline Company

(ANR), Midwestern Gas Transmission Company (via

Tennessee Gas Pipeline Company), Natural Gas Pipeline

Company of America (NGPL), Texas Gas Transmission

49

Several of the major pipeline projects that were planned for

range, but during the nonheating season, usage rates range

between 50 and 70 percent per average day. These figures

indicate that a significant amount of capacity is available

during off-peak periods, even though at the northern end of

the corridor there is a large amount of underground storage

capacity to refill. At the end of the 1995-96 heating season,

for instance, the amount of working gas capacity to be refilled

in the three States at the terminus of this corridor—Illinois,

Indiana, and Kentucky—was approximately 287 billion cubic

feet (Bcf), or the equivalent daily refill requirements of 50

1.4 Bcf per day (210 days in the nonheating season). On this

basis, deliveries to storage would need only about 18 percent

of the daily pipeline capacity available on this route.

In addition, the Eastern Express project would include expansion of Missouri, area. Its operations in Illinois are confined to the area east of St 48

Tennessee Gas’s pipeline (0.2 Bcf per day) between its Niagara, New York, Louis. 

import point and its interconnections near Leidy, Pennsylvania, and its Based on an average 35 percent working gas capacity remaining at the

northern line extending directly to New England. end of March 1996 in all sites located in the three States.

Mississippi River Gas Transmission Pipeline Company (0.7 Bcf per day) 49

also transports gas along this corridor but it terminates in the St Louis,

50
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

In addition, during August 1996 total natural gas consumption Capacity levels on the Panhandle Eastern Pipeline system did

in these three States was only 26 percent as much as that in not increase at all.

January, the month of highest consumption. At this level, and

assuming that deliveries to these three States were only from Market centers located in the Waha and Panhandle area of

this corridor, capacity requirements would be only about West Texas serve this transportation corridor at its apex. At its

1.9 Bcf per day during this off-peak month. Even with the terminus, shippers and traders can link their Texas trading

deliveries to storage considered, pipeline capacity needed to with the Chicago market center. In addition, the Midmeet the needs of the area is less than 50 percent of what is continent market center, located in southcentral Kansas,

already available. Perhaps because of this situation, no provides shippers with the opportunity to do business with

additional capacity is currently planned along this corridor. traders in the other two areas. All four pipelines operating in

 Southwest Panhandle-Midwest

Route is a major link between Waha Hub and Chicago

This corridor extends from the West Texas and Oklahoma

Panhandle areas northward through the major gas production

fields (Hugoton, Panhandle, etc.) located in southwestern

Kansas, and then northeastward toward the Midwest

marketplace (Figure 12). Midway on its course, in Nebraska,

it links with another corridor (see Rocky Mountain-Midwest

section) bringing supplies in from the Rocky Mountain areas

of Wyoming, Utah, and Colorado.

There are four major interstate pipelines that run along this

corridor: ANR Pipeline Company, Panhandle Eastern Pipeline

Company, Northern Natural Gas Company, and Natural Gas

Pipeline Company of America. These four pipelines alone

constitute 67 percent of total pipeline capacity exiting this

area. These pipeline routes, however, represent only about

17 percent of the total capacity into the Midwest Region. The

Trailblazer Pipeline system (average flow of 0.5 Bcf per day

in 1996) ties in Rocky Mountain supplies with an

interconnection to Natural Gas Pipeline Company of America

in Nebraska.

Several of the pipeline companies operating within this

corridor have completed system expansions since 1990,

although the additions were relatively small in comparison

with additions in other corridors. For instance, in 1992,

Natural Gas Pipeline Company of America (NGPL) added

about 90 MMcf per day on the portion of its Amarillo line

coming into Illinois and also improved capacity on its system

coming out of the production areas of West Texas by about

245 MMcf per day. In 1996, Northern Natural Gas Company

(NNG) completed an expansion of 351 MMcf per day on its

west-to-east route, improving service in the area and

extending north to southern Wisconsin. At its terminus, it also

improved its transmission facilities and transport capabilities

in the Texas and Oklahoma panhandles by 310 MMcf per day

in 1991 through 1993. The ANR Pipeline system increased

capacity by 16 percent in this corridor, although this

represented an increase of only about 83 MMcf per day.

51

the corridor have direct or indirect links with each of the

market centers.

Traders and transporters using this corridor can also tie their

business and trading activities in with futures market trading.

Both the New York Mercantile Exchange (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

their trading activities and avoid price volatility risks. Of the 52

two markets, the KCBOT has generated the most interest

since its operational debut in 1995.

Also, because of its links to West Texas and the Oklahoma

Panhandle area, many (spot market) trading points have

become associated with this corridor. Some of the most active

natural gas trading points (on a volume basis) have developed

along it.

Only a limited amount of underground storage capacity is

available to transporters through markets centers located

along this route. Only the Mid-Continent and Chicago market

centers offer any applicable access to storage services for

shippers. However, during the nonheating season a sizeable

amount of capacity on these systems is used to transport

supplies for injection into storage facilities in Illinois, Indiana,

and Michigan. The ANR Pipeline system in particular has a

number of open-access sites located at the northern end of its

system in Michigan. NGPL has a number of storage sites

located in Illinois.

Very little expansion along this corridor is planned over the

next several years. The only significant projects slated for

development are the NGPL Amarillo expansion between Iowa

and Illinois (110 MMcf per day), scheduled for completion in

1998, and the Northern Natural Gas Company’s East Leg

2000 expansion, which will increase service capacity in its

Central and Midwest markets by as much as 450 MMcf per

Energy Information Administration, Natural Gas 1996: Issues and 51

Trends, DOE/EIA-0560(96) (Washington, DC, December 1996), Chapter 3.

The locations of these futures markets in the Waha area of West Texas 52

also enables their services to be available to shippers operating in East Texas

moving supplies through the Texas intrastate system. 
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

day. The fact that these two projects are focused in the design capability of about 300 MMcf per day, when the 53

northern tier of this corridor while the southern section is not northern section of the system is completed (proposed late

slated for significant expansion reflects primarily the ripple 1998), this recently completed section is expected to operate

effect of proposed expansions to Canadian import capabilities. at close to its full capability.

 Southwest-Western

Westward corridor is overbuilt

The Southwest–Western corridor is used to transport supplies

from the Permian Basin area of West Texas, through New

Mexico (where the northern route taps into the San Juan Basin

production area), and westward primarily to California

(Figure 12). Two major interstate pipelines, El Paso Natural

Gas Company and Transwestern Pipeline Company, operate

along this corridor (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 Pacific Gas & Electric

Company, the largest pipelines serving the California

marketplace. In addition, Transwestern Gas Pipeline

Company links with the Mojave Pipeline Company, an

interstate pipeline placed in service in 1992 to transport

natural gas supplies to the enhanced oil recovery (EOR) and

cogeneration customers located in Kern County, California.

During the first part of this decade, these two pipeline systems

expanded considerably: El Paso Natural Gas Company by 19

percent and Transwestern Pipeline by 41 percent. However,

these expansions added capacity into California just when it

was least needed and, as a result, a competitive situation

developed between lower-cost Canadian supplies and

Southwestern regional production. An additional impact was

that unused capacity on these systems not only brought about

a significant drop in load, but in several instances customers

actually turned back contracted capacity, opting instead to

satisfy their needs through the capacity release market.

Compared with 1990, when average daily utilization levels on

the El Paso and Transwestern systems were above 90 percent,

in 1995 average-day utilization levels for the two pipelines

were below 60 percent. Indeed, on its system peak day in

1995, El Paso Natural Gas had only a 66-percent load factor

overall. Transwestern Pipeline’s load factor on its peak day

was 60 percent (Appendix A, Table A5).

The lower section of the long-delayed TransColorado pipeline

system was completed in 1996. The southern 25-mile section

of this 266-mile proposed pipeline system is currently moving

about 120 MMcf per day from the Ignacio area of the

southern Colorado San Juan Basin to the Blanco hub in

northern New Mexico. While this is less than half of its

54

Finally, the completion of Transwestern Pipeline Company’s

San Juan Basin expansion (255 MMcf per day) in 1996

expanded capacity on the New Mexico side of the San Juan

Basin and partially relieved a production constraint situation

that has hindered the flow of production out of the area for

several years. While some of this improved capability will go

to the Western marketplace, a major objective of this project

has been to improve producer access to customers in the U.S.

Northeast and Midwest.

The Blanco (hub) market center, operated by Transwestern

Pipeline Company and located on the New Mexico portion of

the San Juan Basin, has become a major pooling point for

producers in the area and for shippers, especially those

wanting to forward their supplies eastward to the market

centers in West Texas (Waha area) and for transhipment on

the Northern Natural Gas system (an affiliate of

Transwestern), located to the northeast via the Texas and

Oklahoma panhandles (see corridor ).

Nevertheless, a significant amount of West Texas and New

Mexico gas supplies still are transported along this corridor to

Arizona, California, and Nevada. In 1996, more than half of

the natural gas consumed in those States (approximately 994

billion cubic feet) was transported via this route.

There is very little underground natural gas storage capacity

associated with this corridor. At the extreme eastern end of

the corridor, only one site, the Washington Ranch facility

operated by El Paso Natural Gas Company, is reserved

primarily for system support services and is not available for

customer use. At its western end, in southern California, a

limited amount of storage capacity is available to shippers at

five sites operated by Southern California Gas Company

(SoCal). While about 60 percent of this capacity is reserved

for the company’s own use, shippers can access what is

available, as well as such storage-related services as shortterm gas loaning and parking, through the California Energy

market center, which is also operated by SoCal.

Although some of the natural gas injected into these storage

sites comes from producing fields in southern California, a

significant amount of the working gas stored at these sites

This expansion will accommodate shippers on the expanded Northern Blanco County in northwest Colorado to the Ignacio area in southern La Plata 53

Border Pipeline system. County, Colorado.

The TransColorado Pipeline was originally slated for completion in mid- 54

1992 but changing market conditions and other factors delayed construction

until recently. The northern section will run from the Big Hole area of Rio
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

comes out of this corridor. The combined injection rate market center; thus it is strategically located. It lies along a

capability of the five sites is 1.1 billion cubic feet (Bcf) per route that will be expanding to accommodate increasing

day, while their total working gas capacity is 115 Bcf. This amounts of Western Canadian gas being transported to

translates into roughly 104 days needed to fill these sites from Northeast markets via a southern Canadian/U.S. alternative

scratch. But working gas levels at these sites rarely fall below (see below).

30 percent, which means that the equivalent of 55

approximately 83 days per year of about 1 Bcf capacity A large number of underground storage facilities are located

service on the corridor could be said to be carried by storage in proximity to several of the pipeline systems operating in

service operations, or only about 4 percent on an annual basis. this corridor, although not all of them are directly accessible

Because of the excess capacity along this corridor, those 1.8 Bcf per day withdrawal capability) are directly accessible

projects that have been proposed are intended primarily to to shippers using the Great Lakes Gas Transmission system,

support expanded service to the eastern end of this corridor. while the storage facilities located in Illinois and operated by

Nevertheless, the end result of completing these projects will Northern Illinois Gas Company (eight sites, 3.4 Bcf working

be to improve and expand service to the western end as well. gas capacity) are available only through the Chicago Market

For instance, Transwestern Pipeline Company has proposed Center, which is affiliated with the company, or through the

further expansion of its San Juan facilities by up to 245 MMcf company itself. Altogether, the daily injection capability at

per day in 1998, while El Paso Natural Gas Company has storage facilities linked to the receiving end of this corridor

submitted plans for a compression enhancement project in the represents the potential use of about 5 Bcf per day of pipeline

same area, which would improve its capacity by 116 MMcf capacity during the storage refill period from April through

per day. The location of the facilities that are part of these October. If the proposed development of additional pipeline

projects, that is, the San Juan Basin triangle, is such that capacity along this corridor for extension to the Northeast

service benefits will affect area producers and shippers Region is completed, shippers will have access to storage

transporting to either end of the corridor. facilities and local distribution companies located in

 Canada-Midwest 

Corridor is major import route for Canadian gas

This transportation corridor 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

Company and Viking Gas Transmission Company 56

(Figure 13). This tie-in represents about 4.4 Bcf per day of

pipeline capacity, or about 41 percent of total U.S. natural gas

import capacity in 1997. Since 1990, capacity on this route

has increased by more than 40 percent.

Also, another pipeline, the Bluewater system, located at the

eastern end of the corridor and placed in service in 1995, can

transport up to 250 MMcf per day on a bi-directional basis

between the United States (Michigan) and Canada (Ontario).

It was developed primarily to support regional storage

services and business at the regional Grand Lacs natural gas

to shippers. For instance, nine sites (1 Bcf per day injection,

57

Pennsylvania and New York as well. Indeed, some proposals

to expand storage availability in the Northeast to

accommodate this capacity growth are already being put on

the table.58

Expansions have occurred on two of the corridor’s pipeline

systems since 1990: Great Lakes Gas Transmission (GLT)

and Northern Border Pipeline. Capacity on GLT increased

significantly, 620 MMcf per day or 37 percent since 1990.

Increasing imports, nevertheless, kept this corridor operating

at or near capacity during most of the heating season and at

about 90 percent on average throughout 1996 (based on

annual flow). In 1995, the summer load factor averaged about

72 percent. Currently, GLT actually returns about 68 percent

of the gas it imports at Noyes, Minnesota, to Canada via its St.

Clair, Michigan, export point to customers in Ontario or

transshipment to New York State through Ontario. GLT, with

its access to its underground storage sites located in Michigan,

can provide its customers with a seasonal supply backup

depository and a peaking source.

The Northern Border Pipeline (NBP) system expanded by

0.4 Bcf per day, or 39 percent from 1991 through 1993. The

pipeline is currently running at or above capacity throughout

Energy Information Administration, Form EIA-191, “Underground 55

Natural Gas Storage Report.”

Northern Border currently serves the Midwest Region with deliveries to The Chicago Center is only indirectly accessible to shippers using this 56

Northern Natural Gas Company and Natural Gas Pipeline Company of corridor.

America. The pipeline receives large amounts of gas from Canada at Monchy Energy Information Administration, “Underground Storage of Natural

near the Saskatchewan and Montana borders. Monchy is the second 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).

57

58
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

most of the year; its lowest monthly daily average load factor northern TransCanada route and provide an integral link in

in 1995 ran in the neighborhood of 96 percent. Utilization support of Columbia Gas Transmission Company’s

levels on the system currently are higher than they were in Millennium project (see next section). 

1990.

The growth in natural gas demand in Midwestern markets and actually completed, capacity could increase by as much as

the competitive pricing of Canadian natural gas over the past 4.2 Bcf per day over the next several years. This level of

decade spurred most of the expansion activity that has increase is second only to that proposed for development into

occurred on this corridor since 1990. However, some of it has the Northeast Region. However, what really distinguishes the

also been production driven, with Western Canadian growth along this corridor is that the vast majority of new

producers being the initiators. In fact, most of the expansion capacity would be on newly built trunklines bringing supplies

projects recently proposed for development over the next in from Canada.

several years along this corridor fall into this category. The

northeastern section of British Columbia and northern Alberta

have developed into enormous gas-producing 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 such a project is the Alliance project,

which would bring gas from British Columbia to the Chicago,

Illinois, area along the right-of-way of an existing oil pipeline.

The project was initiated by a consortium of Western

Canadian producers dissatisfied with the limited service

offered by the single NOVA(Alberta)-TransCanada system

route currently available to them. If completed, the proposed

Alliance project alone would increase area service along the

corridor by 1.3 Bcf per day. Coupled with the extension of 59

the Northern Border Pipeline (in 1998 and 2000) and the 60

Viking Voyageur project (2000), capacity on this part of the

corridor could increase by more than 172 percent (3.8 Bcf per

day) from 1996 levels (2.2 Bcf per day). 61

Partly in response to producer demands for additional exit

capacity from Alberta and partly because of the potential

competition from proposals such as the Alliance project,

TransCanada has tendered its own expansion plans (1.4 Bcf

per day) to feed into the proposed Viking Voyageur project.

Several U.S. pipeline companies have developed expansion

plans of their own that would tie in with TransCanada’s

additional system expansion plans for 1998 and 1999. These

projects would also increase support to shippers wanting to

transport gas to Ontario, Canada, via an alternative to the

If all of the current proposals associated with this corridor are

 Canada-Northeast

Corridor is target of major expansion proposals

The Canada-Northeast corridor links the eastern portion of the

TransCanada Pipeline system (and Western Canadian gas

production) to six pipeline companies 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. Lawrence Gas Company. Indirectly,

the corridor 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 capacity level of 2.4 Bcf per day. While the

vast majority of the Canadian capacity that comes into the

U.S. Northeast is off the northern tier of the TransCanada

system, about 5 percent represents capacity that traverses the

U.S. Midwest (on the Great Lakes Transmission system),

crosses back into Canada through Ontario, and is imported

once again at Niagara, New York.

Two of the major pipeline systems along the Canada-toNortheast corridor were constructed during the 1990s: the

Iroquois (850 MMcf per day) and Empire (500 MMcf per

day) (Figure 10). Both systems serve primarily customers in

New York State, although the Iroquois system also serves

customers in Connecticut and Massachusetts (Appendix A,

Table A3). These two new lines, plus the smaller North

Country Pipeline also added between 1990 and 1996, alone

increased import capacity to the Northeastern United States

by nearly 300 percent. In addition, Tennessee Gas Pipeline

system more than doubled its import capacity at Niagara, New

York, adding 476 MMcf per day, or about 129 percent to its

1990 level.

The increasing demand for Canadian gas in the Northeastern

United States has been responsible for the very high

utilization rates on the systems operating on this corridor.

Annual average-day usage rates on these pipelines ran about

85 to 90 percent during 1996. During peak periods, the

The proposed border-crossing site for the pipeline is slated to be able to 59

move up to 1.6 Bcf per day of gas if necessary.

In August 1996, the Federal Energy Regulatory Commission approved 60

construction of the Northern Border Pipeline Company expansion project,

which would add 700 MMcf per day to import capacity at the Montana border.

Correspondingly, Foothill Pipe Line Ltd. of Canada, which interconnects with

Northern Border Pipeline at Monchy, Montana, would expand its eastern leg

by the same amount. In February 1997, Foothills Pipeline Ltd., proposed to

expand its system further and conducted an open season to gauge shipper

demand.

Energy Information Administration, Energy Policy Act Transportation 61

Study: Interim Report on Natural Gas Flows and Rates, DOE/EIA-0602

(Washington, DC, October 1995), Table 5, p. 32.
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

principal importing pipeline, Iroquois Gas Transmission Combined with the Millennium import level of 700 MMcf per

Company, was operating about 22 percent above its day and several import expansions related to other projects,

certificated capacity. Even during the summer months, daily such as the Portland Natural Gas Pipeline system,

capacity utilization levels were in the 90 to 100 percent range. TransCanada’s export capacity to the U.S. Northeast could

Iroquois often uses line packing on its system to handle heavy increase by 0.9 Bcf per day by the end of 1999, a 53-percent

demands of shippers. increase over 1996 levels. In conjunction with TransCanada’s

Several natural gas market centers are intricately tied to this proposed an expansion of its import capabilities by 160 MMcf

corridor. At its western end, five market centers are located in per day.

Alberta, Canada. One of these, the AECO-C hub, is a key

trading point on several commercial electronic trading In addition, several new pipelines have been proposed to

systems and is also the point of trade for NYMEX futures move gas supplies being developed off the Canadian Atlantic

contracts transacted for Western Canadian gas. In addition, coast near Sable Island to markets in Canada and the United

several U.S. natural gas trading centers are located at the States. The Maritimes & Northeast pipeline project is slated

eastern end of the corridor, such as the Iroquois, CNG/Sabine, to transport gas from the Sable Island Offshore project. Its

and Ellisburg-Liedy market centers. These centers provide route will take it directly into the State of Maine and through

customers with interconnections to at least 10 interstate New Hampshire to interconnections with the Tennessee Gas

pipeline systems and 4 intrastate systems serving shippers Pipeline system in Massachusetts.

throughout the Northeast. The availability of such active

trading centers at both ends of the corridor provides shippers While this northern tier corridor has been the principal route

with the transportation tools to transact their business used by shippers to import Canadian supplies into the

efficiently. Northeastern United States, the large number of projects

Most of the market centers in this corridor offer customers Midwestern marketplace (see earlier section) has spurred

access to underground storage services, such as gas loaning, several major pipeline companies to plan large-scale projects

temporary gas parking, and load balancing. In Canada, at the that would extend some of this new capacity further eastward

western end of this corridor, approximately 21 Bcf per day of to Northeastern markets. If fully implemented, these projects

daily storage deliverability is available at eight sites. In the would greatly expand the southern tier corridor, which in the

U.S. Northeast, storage deliverability of up to 4.6 Bcf per day past has seen only limited use as a route for imported

is available to shippers through market centers. In addition, supplies.

several storage sites located in Ontario, Canada, are available

to shippers transporting supplies to the area via the Great

Lakes Transmission system.

This corridor is slated to undergo a major expansion over the

next several years. If all the current expansion proposals were

implemented, total direct Canadian import capacity into the

U.S. Northeast could approach 5.0 Bcf per day by the end of

the century, a 110-percent increase over 1997 levels. An

already-approved TransCanada Pipeline Ltd. expansion

project, slated for 1998 with further additions being

considered 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 project.

The Millennium project is projected to start deliveries in the

fall of 1999 to customers in the U.S. Northeast. The proposed

Vector Pipeline, which is a partner with Columbia and

TransCanada in the Millennium project, will tranship supplies

through Canada via TransCanada from its St. Clair, Michigan,

export point to the Millennium pipeline at Niagara, New

York.

62

multi-year expansion plans, Iroquois Pipeline Company has

recently proposed to bring Canadian supplies into the

 Canada-Western

Demand for Canadian gas has increased 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 much of the gas

moving on this corridor reaches California at its northern

border, some of the supplies also reach California by way of

Arizona, being moved south and west via the States of Utah,

Wyoming, and Colorado. 

In Canada, Westcoast Gas Transmission Ltd. and Alberta

Natural Gas Ltd. (in association with Foothills Pipeline Ltd.)

receive gas from the NOVA Gas Transmission Ltd. (the

The Portland Natural Gas Pipeline system (PNGT) (178 MMcf per day) 62

will replace and expand upon the Granite State Pipeline Company’s 31-MMcfper-day import pipeline that brings Canadian natural gas to Maine via Vermont

and New Hampshire. The PNGT system may also be supplemented by LNG

facilities that would be built in Maine.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 

principal pipeline system in the region linked into the major and/or traders to coordinate trading with the pooling and

production areas in Alberta and British Columbia) and aggregation services offered at Sumas.

transport that gas to the U.S. border (Table 8). There the

supplies are received by Northwest Pipeline Company (from Access to underground storage for shippers along this

Westcoast Gas Transmission) and PG&E Transmission corridor is limited. Much of the storage capacity on the

–Northwest (PG&E-NW), formerly Pacific Gas Transmission southern portion is owned and operated by local distribution

(PGT) (from Alberta Natural Gas). The two pipelines have a companies and is used exclusively to support their own

combined capacity of 3.5 Bcf per day, 99 percent of import seasonal storage needs. Nevertheless, shippers can acquire

capacity in the area. This route represents one-third of the access to storage services on an as-available basis through

total capacity reaching the United States from Canada. some of the market center operations. The Pacific Gas and

While PG&E-NW transports most of its gas (about 82 percent provides limited access to its three storage sites in northern

in 1996) directly southward to California, the Northwest California (the center also utilizes PG&E system line packing

Pipeline system extends south and eastward from its border to support its storage parking and loaning services). At the

receipt point, operating on a bidirectional basis along much of Canadian end of the corridor, much of the available storage is

the eastern section. At the northern Nevada State line, intricately linked with market center operations, providing

Northwest Pipeline Company links with the Paiute Pipeline parking and loaning services primarily to producers shipping

Company, which until recently was the only gas supplier to gas to the United States. These Canadian sites are capable of

the Reno, Nevada, area. Only one new pipeline has been handling up to 6 Bcf per day deliverability and have a

added to the corridor since 1990, the Tuscarora Pipeline working gas capacity level of about 412 Bcf.

Company (113 MMcf per day) in 1995. This pipeline

interconnects with the PG&E–NW system at the northern

California border and transports gas to the Reno, Nevada,

area.

Between 1991 and 1996, capacity within this corridor grew

by more than 48 percent (1.2 Bcf per day at the Canadian

border) as capabilities were increased to meet expected

growth in the regional natural gas market (Table 7). While the

downturn in the regional economy during the period led to

some excess capacity, usage levels for 1996 indicate the trend

has turned around slightly, with average utilization levels

along some portions of the corridor actually higher than they

were in 1990 (Appendix A, Table A6).

Shippers using this corridor have access to the services of

several market centers, although the types of available

services are somewhat limited. For instance, within the

California marketplace, the Golden Gate market center, which

is affiliated with the Pacific Gas and Electric Company, limits

its offerings mainly to parking and loaning services and

interconnections with six of the principal pipeline system

located at the southern end of this corridor. The Sumas market

center, which operates in the Washington State/Canadian

border area, provides shippers, primarily marketers and

producers, with a pooling and aggregation point for export

trading. At the apex of the corridor are the AECO-C, Alberta,

Intra-Alberta and Crossfield hubs. These centers are tied

closely to the NOVA pipeline system, which is the exclusive

gas transporter in Alberta. The Intra-Alberta hub, which is

primarily an electronic trading operation, is linked closely

with trading and business conducted at the Sumas market

center. This arrangement allows Alberta producers, shippers,

Electric Company, through its Golden Gate market center,

	 Rocky Mountains-Western

A new westward corridor was built in 1992

This corridor did not exist until 1992, which was the year the

Kern River Pipeline system was completed. This system

extends from the Opal, Wyoming, area southwestward

through Nevada, just north of Las Vegas, to Kern County,

California (Figure 12). Its capacity is approximately 63

750 million cubic feet per day.

The Kern River Pipeline system was developed primarily to

carry gas to the enhanced oil recovery market in southern

California, which has been a substantive natural gas market.

In 1996 its average day utilization rate was 95 percent, while

on its system peak day it operated at 102 percent. In 1997 its

service was extended to the Las Vegas electric power

generation market with the opening of an expanded metering

facility with Southwest Gas Company, the major natural gas

distributor in the Las Vegas area.

Underground storage facilities, although available at the apex

of this corridor 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 vicinity, with a combined daily

deliverability of 0.6 Bcf per day and 66 Bcf of working gas

capacity, only one, Questar Pipeline Company’s Clay Basin

In California, the Kern River Pipeline system physically merges with the 63

Mojave Pipeline system (400 MMcf per day) to form one line serving

customers primarily in Kern County, California. Mojave receives its supplies

from Transwestern Gas Pipeline Company and El Paso Natural Gas Company

at the Arizona-California border. 
Energy Information Administration

 Deliverability on the Interstate Natural Gas Pipeline System

facility (0.4 Bcf per day, 51 Bcf), is accessible to shippers. Kansas City, Missouri. Currently the new line does not

The Western market center, located at the upper end of the provide any interconnections with the two major interstate

system, provides customers with access to the Kern River pipelines connecting this corridor to Midwestern markets;

Pipeline system and to the Clay Basin site. At the southern rather, its full capacity is committed to customers located in

end of the corridor shippers have access to the services of two the Kansas City area.

more natural gas market centers, the California Market Center

(operated by Southern California Gas Company/Enerchange Several market centers are available to shippers using this

Inc.) and the Golden Gate Market Center (Pacific Gas & corridor. Located at the western end is the Western market

Electric Company). center and at the eastern end the Chicago market center. The

Only one expansion along this corridor has been proposed; and with access to the Natural Gas Pipeline Company of

the Colorado Intrastate Pipeline is assessing the feasibility of America’s system, has become a key natural gas trading

expanding its system to serve customers in Nevada along a center for customers along this corridor. The market center in

new 360-mile route (250 million cubic feet per day). This line Wyoming currently has limited business with shippers using

would open a new market for new production out of the the corridor, primarily because available capacity is fully

Powder River Basin in Wyoming. booked on a long-term basis and shippers have little need for

During the early part of the decade, when the proposed and trade administration services. It remains to be seen if

Altamont Pipeline system was under serious consideration as planned expansions along this corridor will increase market

a supplier of Canadian gas to California, the Kern River center activity, as what capacity is coming in service is

Pipeline Company had a proposal on the table to expand its already fully subscribed. 

system correspondingly. However, as a surplus of interstate

natural gas pipeline capacity developed in the Western Region Customers using this corridor have a limited number of

and the proponents of the Altamont system directed their underground storage facilities available for their use. At the

target market eastward, those plans were set aside. terminus of the corridor in Wyoming and Colorado are 18


 Rocky Mountains-Midwest

Corridor is expected to become more important as

transportation capacity expands

This corridor links Rocky 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 corridor itself does not extend into the

Midwest, the several pipelines operating along this route

interconnect with major trunklines bringing supplies from the

Southwest to Midwestern markets (see ).

The Trailblazer System, which is a contiguous 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 America

pipeline. The Williams Natural Gas Company and the KN

Interstate Pipeline Company also operate along this corridor,

but these two pipelines serve primarily local regional markets

(Table 8).

In late 1997, the KN Interstate Pipeline Company completed

its Pony Express Pipeline (255 million cubic feet per day).

This line is the first new long-distance line completed in this

corridor since the Trailblazer Pipeline was installed during the

early 1980's. The line runs from central Wyoming to south of

Mid-Continent market center, located in southcentral Kansas

transportation, title transfers/tracking, buyer/seller matching,

sites that customers may access. Much of the storage located

at this end, however, is used to support local producers and

distribution companies. In the Chicago area corridor, shippers

have access to storage facilities associated with the Chicago

market center. 

Compared with most of the other corridors, this particular one

is relatively small. Its importance, however, lies in its future.

Currently the Trailblazer system is fully utilized throughout

most of the year as the demand for lower priced Rocky

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 excess of pipeline capacity during the past several years

and is currently considered a soft market for natural gas. With

the emphasis on the Western market, development of

eastward bound pipeline capacity 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 corridors examined

in this chapter reflect only that portion of the network which

involves long-haul operations. At the regional level, many

other smaller interstate, intrastate, and local distribution

systems have the responsibility of delivering gas to the
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 	

ultimate consumer (see Chapter 4). In addition, there are could add as much as 5.0 Bcf per day to U.S. import capacity

numerous natural gas gathering systems that carry out the task from Canada along these corridors, a 45-percent increase over

of feeding supplies to the long-haul segment of the network 1997 levels. This anticipated growth reflects the continuing

(see Chapter 2). U.S. demand for Canadian natural gas, especially in the

Between 1990 and the end of 1997, capacity additions on Western Canadian producers to expand further into these

these long-haul corridors totaled more than 12.4 billion cubic markets.

feet (Bcf) per day, an increase of about 17 percent. Most of

this construction entailed expansions to existing mainline While the northern corridors predominate in respect 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 combined increase in gas productive capacity is also currently being developed in

new or expansion capacity, 27 percent of the total, occurred the Gulf of Mexico. The logical markets for this natural gas

along those corridors transporting supplies from Canada are in the Midwest and Northeast United States, the same

(1.2 Bcf per day), the Rocky Mountains (0.8 Bcf per day) and markets slated for the Canadian expansions (as well as the

the Southwest (1.0 Bcf per day) to the Western Region of the expanding Rocky Mountain corridor). Yet, no major

United States. On a singular basis, the largest increase in expansions along the corridors linking the Gulf of Mexico to

capacity occurred on the corridor leading from Canada to the these marketplaces have been announced. During the summer

Northeastern United States, which grew by 1.9 Bcf per day, months, even with market storage refill supplies using

or over 400 percent. significant levels of available capacity, a number of the

No matter how it is viewed, the corridors with the largest of unused capacity available. This available capacity could

growth in deliverability since 1990 have been those coming absorb much of the Gulf’s new-found production during offinto the United States from Canada. These corridors 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 capacity

the pipelines in these corridors operating above 90 percent constraints could develop. If deep-water development

throughout most of the year. The comparatively lower cost of continues over the next decade, most likely some

Canadian supplies over the past several years has been a key complementary onshore expansions would occur along these

factor in maintaining these high utilization levels. corridors.

Based on current expansion proposals, the most extensive Although there are a few natural gas transportation corridors

development of new capacity over the next several years will that are capacity constrained and/or are operating at close to

occur along these same corridors, except for the one directed full utilization throughout the year, the current capabilities of

toward the Western States. At least four new pipelines and the pipeline network in North America are sufficient to meet

several expansions are planned that will expand deliverability the current level of demand. And, project proposals are on the

not only to the U.S. Midwest and Northeast markets but also table which will alleviate those few exceptions where

to Canadian domestic markets. These projects will improve limitations exist. In fact, on the surface it appears that an

access to natural gas supplies in Western Canada and also excess in pipeline capacity could develop along several

create a new corridor that will bring production from the corridors, especially if anticipated demand does not live up to

developing fields off the coast of Eastern Canada (Sable expectations.

Island) to Canadian and U.S. markets. These expansions

64

Midwest and Northeast regions, and the desire on the part of

pipelines along these corridors still have significant amounts

The volume increase would be 37 percent more than the total Canadian 64

import capacity added from 1991 through 1996, 4.3 Bcf per day.
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 51

4. Deliverability to Markets

Each regional market in the United States has widely varying (Table 9). It is the second coldest region (Table 10) and

patterns of energy use and natural gas requirements. has a substantial spaceheating market. Residential and

Different regional demographics, weather patterns, and industrial customers in the Midwest consume more

distinct natural gas customer profiles result in different market natural gas as a percentage of total energy (25 percent)

needs and consumption levels. The numerous natural gas than any other regional market except the major

pipeline systems that have evolved over time to provide production area of the Southwest (Table 11).

transportation services to and within these end-use markets

are designed to accommodate these variations. For instance,  Northeast: This region is the most heavily populated and

in the colder, seasonal markets, regional natural gas is the largest consumer of energy. Yet natural gas

distribution systems are designed to meet space-heating represents only 21 percent of all energy consumed, a

demands by residential and commercial customers and are comparatively low percentage (Table 11), especially

interlaced with wintertime backup (underground storage) and since the region has very cold winters. However, natural

peaking facilities. In less weather-sensitive markets where gas use has increased at an annual rate of 4.9 percent

natural gas demand is mainly for electric power generation since 1990. Coincidently, this market is a principal target

and/or industrial usage, storage is needed less for backup and for Canadian import expansions during the next several

more to support some short-term fluctuations in demand and years (Appendix B). 

pipeline transportation system balancing.

Except for those markets in the vicinity of major natural gas in the Nation and consumes the second smallest amount

production 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 coming out

the regional pipeline network that directs the natural gas to the of the Southwest (Texas and Louisiana) en route to

eventual consumer. The capability of the longhaul “trunkline” Midwest and Northeast markets travel through the

usually reflects the needs of regional “grid” pipeline Southeast Region. Industrial use of natural gas is the

distributors, which sometimes are other major interstate largest consuming sector in this region, with 44 percent

companies but most often are local distribution companies. of the market (Table 12).

This chapter discusses natural gas deliverability to end users  Southwest: This region not only produces the most

in six U.S. geographic market areas: the Central, Midwest, natural gas but also consumes the most. The industrial

Northeast, Southeast, Southwest, and Western regions. The sector’s share of the natural gas market is 53 percent,

emphasis is upon the capabilities, that is, the capacity and eight times that of the residential (Table 12). Export

utilization, of the interstate natural gas pipelines supplying pipeline capacity exceeds incoming by a factor of 12 to

natural gas to and within each region (see Appendix A for a 1, with 16 major interstate pipeline companies beginning

detailed listing of the pipeline companies serving individual in the region (Appendix A, Table A5). Much of the

States). Changes in deliverability since 1990 and planned deliverability within the market is handled by a large

expansions through 2000 are also highlighted. network of intrastate pipeline companies.

The profile of the customer base is addressed to provide some  Western: The Western Region is served by the least

insight into the current operation of pipeline and storage fa- number of interstate pipeline companies (seven) and has

cilities in the market area. Each regional market is unique. the least amount of pipeline capacity entering the region,

 Central: This market is the largest in area but is the least natural gas coming into the region is consumed there.

populated and produces more natural gas than it The market is a large consumer of Canadian natural gas.

consumes, despite having the coldest weather (on

average) of the regions. As a result, it is a net export

market (Figure 13). Most of the capacity entering the

region from Canada and the Southwest actually ends in

the Midwest market.

 Midwest: More natural gas pipeline capacity enters this

market than any other, 24.8 million cubic feet per day

 Southeast: This region has some of the warmest States

10.1 million cubic feet per day. However, almost all

Major Market Changes, 1990-1996

From 1990 through 1996, natural gas pipeline deliverability

to the major U.S. markets increased significantly. On the

interstate pipeline system alone, deliverability increased by
M idwest Western Northeast Southeast Central Southwest Canada

-40,000

-30,000

-20,000

-10,000

0

10,000

20,000

M illion Cubic Feet per Day

Energy Information Administration 

52 Deliverability on the Interstate Natural Gas Pipeline System

Figure 13. Net Natural Gas Pipeline Capacity Entering (-Exiting) Each Region, December 1997

Source: Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline Capacity Database, as of

December 1997.

more than 15 percent, or 10.9 billion cubic feet per day of 78 percent, 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

consumption, 3.0 percent per year (Table 11). This increase Western and Southwest regions. In some areas of only

reflects the growing demand for natural gas and its increasing limited capacity expansion, the increase in pipeline usage

contribution to the total national energy consumption picture. rates reflects a greater use of existing capacity that had

Some of the major changes include: been previously underutilized because of previous

 Expansion of pipeline capacity to high demand

markets. The largest increase in interregional capacity  Elimination of some previous deliverability

during the 6 years was in deliverability to the Western bottlenecks. Although average usage rates have

Region, 3.2 billion cubic feet per day or 45 percent. increased, the reported occurrence of market area

Second largest was a 24-percent increase into the deliverability constraint is rare. In fact, many of the

Northeast Region, or 2.4 billion cubic feet per day capacity additions in recent years have been to improve

(Table 9). The development of so much capacity in the the capability of the regional pipeline systems and their

West led to a surplus of capacity and an overall drop in service to local markets. In 1997 alone, excluding the

the pipeline capacity usage rate, whereas in the exporting Southwest Region, 19 of the 31 completed

Northeast, demand growth fully supported the increase. expansion projects affected service totally within the

In fact, pipelines into the Northeast saw a substantial market area. The Northeast had the highest, with 11 of

increase in average daily usage rates, up 6 percentage 12 projects fitting into this category. Currently, capacity

points from 1990 levels. 

 Higher pipeline utilization rates. During the period,

interregional usage rates increased by 7 percentage

points, reaching a high of 75 percent (on an average day)

in 1996. Pipeline usage rates within several major market

areas also grew significantly. For instance, usage rates

into the Midwest rose 14 percentage points to an average

65

overbuilding or a temporary drop in demand.

66

Based only upon pipelines for which some flow was reported for a 65

known State-to-State capability.

The number and instances of pipeline service curtailments have 66

decreased in recent years because of improved deliverability and system

efficiencies, but serious system instabilities still occur that limit, and

sometimes restrict, the free flow of natural gas to customers. When system

instabilities do occur, pipeline operators have the option of executing what are

known as operational flow orders (see Box, “Operational Flow Orders” in

Chapter 1).
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 53

Table 9. Interregional Pipeline Import Capacity, Average Daily Flows, and Usage Rates, 1990 and 1996

Receiving Sending (MMcf per Day) (MMcf per Day) (percent)

Region Region

Capacity Average Flow Usage Rate1

1990 1996 Change 1990 1996 Change 1990 1996 Change

Percent Percent

Canada Central 66 66 0 44 4 -99 67 4 -63

Midwest 1,211 2,543 110 961 1,626 69 79 68 -11

Total into Region 1,277 2,609 104 1,005 1,630 62 79 68 -11

Mexico Southwest 354 844 138 38 83 117 11 10 -1

Western 45 45 0 5 9 86 11 21 9

Total into Region 399 889 123 43 92 113 11 10 -1

Central Canada 1,254 1,563 25 941 1,542 64 75 99 24

Midwest 1,765 2,354 33 974 1,564 61 86 94 8

Southwest 8,555 8,609 1 4,119 4,993 21 49 60 11

Western 250 298 19 196 4 -- 78 0 --

Total into Region 11,824 12,824 8 6,230 8,099 30 57 70 13

Midwest Canada 2,161 3,049 41 1,733 2,581 49 84 85 1

Central 8,988 9,879 10 5,684 7,714 36 63 78 15

Northeast 2,024 2,038 1 714 910 27 45 45 0

Southeast 9,645 9,821 2 6,134 8,020 31 64 82 18

Total into Region 22,818 24,787 9 14,265 19,224 35 64 78 14

Northeast Canada 467 2,393 412 309 1,834 494 66 77 11

Midwest 4,584 4,887 7 3,474 4,220 21 76 86 11

Southeast 4,971 5,149 4 4,091 4,431 8 82 86 4

Total into Region 10,022 12,429 24 7,874 10,485 33 79 85 6

Southeast Northeast 100 520 417 63 15 -78 63 60 -3

Southwest 19,801 20,846 5 14,613 16,063 10 74 77 3

Total into Region 19,901 21,366 7 14,676 16,078 10 74 77 3

Southwest Central 1,283 2,114 64 572 1,267 122 68 70 2

Mexico 350 350 0 0 37 -- 0 11 --

Southeast 405 405 0 75 60 -20 79 86 7

Total into Region 2,048 2,869 40 647 1,364 111 69 61 -8

Western Canada 2,421 3,786 56 1,874 3,275 75 77 87 10

Central 365 1,194 227 196 713 264 54 95 41

Southwest 4,340 5,351 23 3,910 2,415 -38 90 45 -45

Total into Region 7,126 10,331 45 5,980 6,403 7 84 62 -22

Total Within Lower 48 States 73,739 84,606 15 49,672 61,655 24 68 75 7

Usage Rate shown may not equal the average daily flows divided by capacity because in some cases no throughput volumes were reported 1

for known border crossings. This capacity was not included in the computation of usage rate. 

MMcf = Million cubic feet. -- = Not applicable.

Sources: Energy Information Administration (EIA). Pipeline Capacity: EIAGIS-NG Geographic Information System, Natural Gas Pipeline

State Border Capacity Database, as of December 1997. Average Flow: Form EIA-176, “Annual Report of Natural and Supplemental Gas Supply

and Disposition.” Usage Rate: Office of Oil and Gas, derived from Pipeline Capacity and Average Flow.

constraints appear to be limited mainly to production consumption is larger than the growth in total energy use

areas, a fact that is reflected in the number of planned in the United States. The increase has been especially

expansions through 2000 that address this problem. noticeable in the Northeast market, where natural gas use

 Larger natural gas share of energy market. On an use increased at a rate of only 1.2 percent (Table 11). The

annual percentage change basis, the increase in natural gas difference is even more dramatic in the Western Region,

grew at an annual rate of 4.9 percent while overall energy
Energy Information Administration 

54 Deliverability on the Interstate Natural Gas Pipeline System

Table 10. Regional Weather and Gas Storage Profile, 1996

Region Region 1990) Coldest) (MMcf) (MMcf/d) (percent) (percent) Pipeline Independents Operated (MMcf) (MMcf/d)

Number of Normal Weather

Interstate Heating Ranking From From Percent Percent

Pipelines Degree Among Working Convent- High- Operated Percent LDC

Operating Days States Gas ional Deliverability by Operated Owned Peak-Day

in (1960- (1 = Capacity Total Storage Storage Interstate by and Capacity Support

Natural Gas Underground Storage LNG Peaking

Supplies Peak-Day Withdrawal Capability (Deliverability)

Central 21 7,061 1 565,894 6,037 97 3 81 3 16 4,921 416

Midwest 17 6,867 2 1,130,475 24,000 99 1 33 6 61 17,722 2,685

Northeast 15 6,029 3 669,842 11,701 98 2 94 0 6 31,765 3,759

Southeast 18 2,946 6 173,717 5,220 53 47 70 13 17 25,044 2,841

Southwest 35 3,096 5 982,532 20,500 59 41 38 29 33 6,588 669

Western 10 4,517 4 244,206 7,120 100 0 0 0 100 6,780 811

U.S. Total -- -- -- 3,766,666 74,578 85 15 70 13 17 92,820 11,181

MMcf/d = Million cubic feet per day. LDC = Local distribution company. LNG = Liquefied natural gas. -- Not applicable.

Sources: Normal Heating Degree Days: U.S. Department of Commerce, National Oceanic and Atmospheric 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 Geographic Information System,

LNG Database, as of December 1997.

Table 11. Regional Energy Profile Comparison of Annual Average Change, 1990-1995 or 1990-1996

Region Change 1995 Change Consumed Consumption) Change Consumption

Population Overall Energy Consumption Natural Gas Consumption

 Ratio of

1990-96 1990-95 As Percent U.S. 1990-95 Natural Gas

1996 Percent Quantity U.S. Percent of Total Quantity Ranking Percent Production

Estimated Annual 1995 Ranking Annual Energy 1995 (Natural Gas Annual (1996) to

(millions) (trillion Btu) (trillion Btu)

Central 20,995 2.1 7,435 6 2.1 24 1,749 6 3.8 1.39

Midwest 48,272 1.2 16,963 3 1.1 25 4,302 2 2.9 0.08

Northeast 66,421 0.7 18,433 1 1.2 21 3,850 3 4.9 0.10

Southeast 48,967 2.7 16,497 4 2.2 15 2,415 5 2.9 0.28

Southwest 31,003 2.9 17,258 2 1.3 39 6,797 1 0.2 2.25

Western 47,835 2.9 12,836 5 0.3 21 2,642 4 4.0 0.11

U.S. Total 263,493 1.9 89,422 -- 1.3 24 21,753 -- 3.0 0.88

-- Not applicable.

Sources: Natural Gas Production and Consumption: Energy Information Administration (EIA), Form EIA-176, “Annual Report of Natural

and Supplemental Gas Supply and Disposition.” Energy Consumption: EIA, State Energy Data Report, Consumption Estimates 1980-1995

(December 1997). Population: U.S. Department of Commerce, Bureau of the Census.

where natural gas use increased annually by 4.0 percent market fell 2 percentage points between 1990 and 1996,

while total energy grew by only 0.3 percent. California with the largest decreases occurring in the Western

experienced a 0.4 percent drop per year in overall energy (6 points) and Northeast (5 points) marketplaces

production during its economic slowdown of the early (Table 12), usually heavy markets for electric power

1990s, a drop that brought down the regional average generation. Actual natural gas consumption by electric

(Appendix C, Table C2). But as a percentage of total utilities also decreased nationally but only slightly, at an

energy consumption, natural gas still retained its 21- annual average rate of 0.4 percent during the same

percent share of the Western regional energy market, the period. The only markets to show a gain in electric utility

same as in 1990. consumption were the Southeast and Midwest regions,

 Decrease in natural gas use by electric utilities. The

electric utility sector’s share of the U.S. natural gas

8 and 10 percent per year, respectively. Only in the
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 55

Table 12. Regional Natural Gas Customer Market Share Changes, 1990-1996

(1996 Volumes Consumed -- Billion Cubic Feet)

Region dential mercial trial Utilities Other Resi- Com- Indus- Electric Resi- Com- Indus- Electric 

 (Consumption) (vol.) (vol.) (vol.) (vol.) (vol.) dential mercial trial Utilities Other dential mercial trial Utilities Other

1996 Share of the Natural Gas Market Share Change Since 1990 Consumption

 (percent) (percentage point) (percent)

Average Annual Change in

Resi- Com- Indus- Electric 1

1 1

Central 33 21 30 2 14 0 -1 2 -1 -1 3.5 2.8 4.6 -4.3 2.3

(1,779) (589) (362) (540) (41) (247)

Midwest 40 20 35 2 2 1 -1 0 0 0 3.7 2.3 3.4 10.3 5.4

(4,413) (1,782) (899) (1,557) (78) (97)

Northeast 35 23 31 8 3 -3 2 6 -5 0 3.3 5.6 8.4 -4.7 6.2

(3,702) (1,300) (859) (1,131) (300) (112)

Southeast 20 14 44 16 7 2 0 -3 2 -1 5.8 4.0 3.2 8.3 3.1

(2,377) (476) (331) (1,023) (384) (163)

Southwest 7 5 53 22 14 0 6 -2 -4 1.9 1.4 3.2 -0.1 -3.6 a

(6,715) (443) (307) (3,552) (1,492) (921)

Western 25 15 39 16 5 -2 -2 8 -6 1 0.0 -1.2 5.0 -4.6 9.6

(2,527) (635) (370) (991) (405) (126)

U.S. Total 24 15 41 13 8 1 0 3 -2 -1 3.0 2..8 4.0 -0.4 -0.5

(21,513) (5,225) (3,128) (8,794) (2,700) (1,666)

Includes natural gas used as a vehicle fuel, in pipeline and natural gas plant operations, and in association with production and gathering 1

facilities.

Between plus 0.5 percent and minus 0.5 percent. a

Note: Totals may not equal sum of components because of independent rounding.

Source: Energy Information Administration, Form EIA-176, “Annual Report of Natural and Supplemental Gas Supply and Disposition.”

Southeast Region did the electric utility sector increase cogeneration facilities, the industrial sector’s share of

its share of the natural gas market. the natural gas market increased to 33, 29, and

 Substantial growth in industrial gas consumption, average use per industrial customer increased the most in

especially for electricity cogeneration. The industrial the Southwest Region, at an average annual rate of 67

sector’s use of natural gas increased substantially in 16.0 percent (Table 13). Average industrial consumption

several markets, principally because of significant per customer in the Western and Northeast regions 68

growth in electricity cogeneration, which is primarily increased at an annual rate of 8.4 and 9.7 percent,

natural-gas based, and also because of the relatively low respectively, yet the number of industrial customers in

natural gas prices in comparison with other fuels. In the these markets actually fell. The number of industrial 69

Northeastern States of New Jersey, New York, and consumers increased in the other regions.

Massachusetts, which have a large number of

70

28 percent, respectively (Appendix C, Table C3). The

 Increased deliverability from storage. A major increase

in deliverability from underground storage facilities since

1990 has complemented pipeline expansions in several

markets. Since 1993 alone, daily deliverability from

storage increased by 12 percent, with the largest increase

occurring in the Southwest, most of it high-deliverability

storage. This type of storage is used extensively in the 71

Natural gas used in cogeneration facilities is categorized and included in 67

the industrial sector rather than the electric utility sector, because cogeneration

represents electricity generated as a byproduct of industrial/commercial

processes.

While the number of natural gas industrial customers has declined since 68

1990 by about 1.0 percent per year, this sector’s consumption of natural gas

rose by more than 3 percent per year between 1990 and 1996 as average usage

per customer rose 5.1 percent per year (Table 13). More than 600 nonutility generating facilities are currently operating in

In 1995, nonutilities (cogenerators) accounted for 13 percent of all the Northeast Region, up about 12 percent since 1992—New York has 183; 69

electric power generated in the United States, up from 7 percent in 1990. In New Jersey, 61; and Massachusetts, 68.

1996, 60 percent of cogenerated power was created by burning natural gas. See, Energy Information Administration, “U.S. Underground Storage of

Derived from Energy Information Administration, Form EIA-867, “Annual Natural Gas in 1997: Existing and Proposed,” Natural Gas Monthly,

Nonutility Power Producer Report.” DOE/EIA-0130(97)/9) (Washington, DC, September 1997).

70

71
Energy Information Administration 

56 Deliverability on the Interstate Natural Gas Pipeline System

Table 13. Regional Natural Gas Customers, Average Annual Change, 1990-1996

Residential Customers Commercial Firms Industrial Firms Electric Utilities

Annual Change Annual Change Annual Change Annual Change

(percent) (percent) (percent) (percent)

1

Region 1996 of Users Use 1996 of Users Use 1996 of Users Use Units Units Capacity Capacity

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

In In

Number Number

Central 5,562,943 1.8 1.5 608,800 1.9 0.8 15,004 1.5 3.2 -1.3 -1.0 -0.5 1.2

Midwest 13,220,238 1.6 2.0 1,113,287 1.6 0.7 65,024 0.8 2.6 -0.6 0.3 0.3 8.0

Northeast 12,829,400 1.1 2.1 1,154,093 1.8 3.8 50,795 -1.5 9.7 -1.1 0.4 0.1 4.4

Southeast 5,908,364 2.9 2.7 600,971 2.6 1.3 17,251 1.9 1.4 0.1 3.2 1.2 4.2

Southwest 6,282,924 1.2 0.6 586,329 2.2 -0.9 15,936 -7.8 11.0 0.1 -0.1 0.5 1.4

Western 11,347,439 1.7 -1.7 641,192 0.9 -2.1 41,837 -3.4 8.4 0.3 0.9 0.1 0.3

 U.S. Total 55,151,308 1.6 1.4 4,704,672 1.8 1.0 205,845 -1.0 5.1 -0.5 0.3 0.3 2.5

Includes both primary and secondary generating units. 1

Source: Natural Gas Usage: Energy Information Administration (EIA), Form EIA-176, “Annual Report of Natural and Supplemental Gas Supply

and Disposition.” Electric Generation Capacity: EIA, Form EIA-860, “Annual Electric Generation Report” (1990-1996).

region not only to support the swing demands of local production of about 2.3 trillion cubic feet accounted for

industrial and electric utility customers but also to approximately 11 percent of the total gas consumed in the

support short-term transportation-balancing needs and Nation. Its exported production represented about 2 percent

provide incremental peaking supply for customers in of the natural gas consumed elsewhere in the country. This

distant markets, such as the Northeast and Midwest. In region had the largest production increase in the Nation

the Northeast market, where open-access interstate between 1990 and 1996—0.5 trillion cubic feet, or 30 percent.

storage deliverability represents 94 percent of all

available, several of the largest proposed pipeline The region is the largest in area and the least populated. The

expansion projects include improved access to existing total volume of gas consumed in the region in 1996,

storage sites and expansion of their deliverability 1.8 billion cubic feet, was also the least consumed in the six

(Table 10). regions. Much of this gas is consumed for space heating, as it

Regional Overviews

The natural gas pipeline capacity profile of each region in the

country has evolved over time to meet its particular

requirements. Each region differs in climate, underground

storage capacity, number of pipeline companies, and

availability of local production. Additionally, the varying

demographics of each region dictate different patterns of gas

use and potential for growth. 

Central Regional Market

The Central Region produces more gas than it consumes and

therefore is a net exporter of natural gas. Its 1996 natural gas 72

73

has the second highest percentage of households using natural

gas.

The region’s cold winters, combined with the lowest

residential prices for natural gas of any region, help make the

residential sector a very large consumer of natural gas. The

residential sector accounted for 33 percent of all natural gas

consumed in the region in 1996 (Table 12). Plentiful supplies

from production and storage sites within the region and

adequate capacity on local transmission and distribution lines

ensure that peak demands of residential customers are met

during the winter.

The industrial sector is also a large consumer of natural gas

(30 percent), while natural gas use for electric power

generation in the region constitutes only 2 percent of natural

gas usage, one of the lowest rates among the six regions.

Because it is a major producer of natural gas, almost

14 percent of gas consumption in the region in 1996 was

Still, 4 of the 10 States in the region, Iowa, Missouri, Nebraska, and 72

South Dakota, are almost totally dependent on the interstate pipeline network See, Energy Information Administration, Natural Gas Annual 1996,

for their supplies of natural gas (Appendix C, Table C2). DOE/EIA-0131 (Washington, DC, September 1997) and previous editions.

73
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 57

devoted to natural gas production and transportation-related 10.3 Bcf on their individual system peak days at

activities (Table 12). 1,742 delivery and/or pipeline interconnect points. In

Although it is not as highly populated as the other regions, the deliveries and/or interconnections with the interstate system

Central Region has several large metropolitan markets, which to support local markets. The largest service commitments

are major customers of the interstate pipeline network. To of the interstate pipeline companies are for deliveries to other

name the largest: Denver, Colorado; Salt Lake City, Utah; interstate pipelines within the region rather than to LDCs. For

Kansas City, Kansas and Missouri; and St. Louis, Missouri. instance, Northern Border Pipeline Company delivers more

Large underground natural gas storage facilities are located in than two-thirds of its shipped volumes to other interstate

proximity to these areas The local distribution companies pipeline companies, while the rest is delivered to small

(LDCs) serving these markets account for about 16 percent of customers in the region.

the total storage deliverability in the region (Table 10). LNG

peaking supplies are found only in Iowa and Nebraska, two Of the regional interstate pipeline companies, the largest

States with limited underground storage capacity and no local State-to-State capacity is 972 million cubic feet per day on

production capabilities (Appendix C, Table C1). Williams Natural Gas Company's line from Kansas to

Entering/Exiting Capacity

In 1996, approximately 12.8 billion cubic feet (Bcf) per day

of pipeline capacity entered the Central Region (Figure 14),

8 percent above the 1990 level (Table 9). Only about

10 percent of that capacity was destined for markets within

the region. Twelve pipeline systems enter the region from the

south and east, while four enter from the north carrying

Canadian supplies (Appendix A, Figure A1). The average

utilization rates for pipelines transporting Canadian gas tend

to be higher than those carrying domestic supply, 99 percent

versus about 60 percent from the Southwest and 94 percent

from the Midwest (Table 9). Nevertheless, because of an

increase in regional production and in natural gas demand in

both the Midwest and Central regions during the past 5 years,

capacity usage on lines transporting domestic supply from the

south and east also increased substantially, about

10 percentage points since 1990. Another factor in the

increased pipeline usage rates has been the more efficient use

of capacity during off-peak periods via the capacity release

market. 

Most of the capacity exiting the region (52 percent) flows to

Illinois in the Midwest Region, with the pipeline systems

involved operating at average utilization rates of 83 percent

in 1996 (Appendix A, Table A1). Since 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 percent.

Deliverability Within the Region

Eight of the interstate pipeline companies traversing the

Central Region also have major service commitments within

the region (Figure 14), accounting for 80 percent of their

peak-day deliveries. In 1996, these pipeline systems operated

at an average utilization rate of about 80 percent, delivering

addition, a number of intrastate pipeline companies provide

74

Missouri (Appendix A, Table A1). However, the average

usage rate on this and similar service lines in the area is low,

primarily because of the seasonal nature of the service; low

summertime flows tend to offset the high winter flows. In

1996, for instance, capacity utilization on Williams’ line from

Kansas to Missouri was only 27 percent. Of all the interstate

pipeline companies serving the region, Northern Natural Gas

Company has the largest State-to-State pipeline capacity,

2.1 Bcf 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 capacity of up to

1.5 Bcf per day, mostly supplied by Williams Natural Gas

Company. Kansas Power & Light also accounts for two-thirds

of the reserved capacity 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, which serves the Salt Lake City area

and accounts for 99 percent of the total shipments on

interstate natural gas pipelines operating in Utah. Questar

Pipeline Company, an affiliate, supplies the needs of this

distribution company. The Public Service Company of

Colorado is the major distributor of gas in Colorado, with

more single-State end-use customers than any other company

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 facilities

are used to store excess production rather than to serve as a

supply source for local markets. Second, the region has the

Energy Information Administration, Form EIA-176, “Annual Report of 74

Natural and Supplemental Gas Supply and Disposition.”
1,194

Western

Region

ID

AZ

NV

1,563

Canada

629

444

298

1,563

66

1,785

223

388

525

2,114

250

1,965

127

1,270

NM

250

845

620

1,615

Southwest

Region

276

8,609

268

1,729

450

385

200

564

70 2,625

30

540

597

693

40

4,005

OK

5,272

47

2,531

26

1,655

MN

84

1,575

53

680

AR

WI

1,370

2,953

2,814

3,901

IL

9,879

695

TN

KY

Midwest

Region

2,354

Iowa

Kansas

Nebraska

North Dakota

South Dakota

Montana

Wyoming

Utah Colorado

Missouri

Leaving: 13,253 

Entering: 12,824 

Estimated Total Throughput Capacity

Energy Information Administration 

58 Deliverability on the Interstate Natural Gas Pipeline System

Figure 14. Interstate Natural Gas Capacity Summary for the Central Region, 1996

(Volumes in Million Cubic Feet per Day)

Principal Interstate Natural Gas Pipeline Companies Operating in the Central Region

Regional Service Level Systemwide Utilization Rates %1

Pipeline Name Source(s) Configuration Deliveries Points nects Average Day Offpeak

Regional Secondary System of of

Supply System Peak-day Delivery Intercon- 12-Month Peak Summer

Primary/ Percent of Number Number

2 3 45 6

Regional Pipelines

Colorado Interstate Gas Co CE, SW Trunk/Grid 94 120 17 82 104 76

KN Interstate Gas Co CE, SW Trunk/Grid 80 381 13 79 91 69

Mississippi River Transmission Corp. SW Trunk/Grid 16 21 0 85 92 59

Northern Border Pipeline Co Canada Trunk 90 12 3 98 105 96

Northern Natural Gas Co SW Trunk/Grid 41 219 3 92 107 80

Questar Pipeline Co CE Grid/Trunk 100 29 13 79 81 62

Trailblazer Pipeline Co CE Trunk 100 3 3 97 132 89

Williams Natural Gas Co SW, CE Grid 96 811 16 75 82 42

Williston Basin Interstate PL Co CE Grid/Trunk 100 271 4 83 98 40

Wyoming Interstate Gas Co CE Trunk 100 0 3 93 107 86

Supplemental Pipeline Service

ANR Pipeline Co SW Trunk/Grid 1 69 2 70 100 66

Kern River Gas Transmission Co CE Trunk 1 9 0 98 109 96

Natural Gas Pipeline Co of America CE, SW Trunk/Grid 7 74 13 84 96 80

Noram Gas Transmission Co SW Grid/Trunk 1 3 1 56 86 61

Northwest Pipeline Co Canada Trunk/Grid 34 46 9 90 94 54

Panhandle Eastern Pipeline Co SW Trunk 11 41 4 78 98 58

Texas Eastern Transmission Co SW Trunk 1 10 0 84 109 49

Viking Gas Transmission Co Canada Trunk 3 3 0 85 105 82

Usage rates are based upon capacity and transportation volumes for the whole system and do not represent regional service only. 1

"Trunk” systems are long-distance trunklines that generally tie supply areas to market areas. “Grid” systems are usually a network of many interconnections and 2

delivery points that operate in and serve major market areas. Some systems are a combination of the two.

Represents the percent of total pipeline system volume delivered within the region on the system peak-day occurring in the 1996-97 heating year. 3

Represents total system capacity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 4

Represents total system capacity divided by the single peak-day volumes delivered in the 1996-97 heating year as reported in FERC Form 2. 5

Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based on 6

FERC Form 11 gas delivery data for 1995) divided by 153 days. April and October are considered to be months that “shoulder” the heating season of November-March.

Sources: Capacity: Federal Energy Regulatory Commission, FERC 567 Capacity Report, “System Flow Diagram” and Annual Capacity Report (18 CFR §284.12);

Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity, as of December 1997. 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.”
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 59

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 capacity of 164 Bcf. However, commercial customers increased, whereas in three States the

the total regional working gas storage capacity number of industrial customers dropped by more than

(approximately 566 Bcf) is only 15 percent of the U.S. total 6 percent per year (Appendix C, Table C4). Yet, the average

(Table 10), while daily deliverability from storage is only use by industrial customers increased at an annual rate of

6 Bcf per day, or 8 percent of the U.S. total. 3.2 percent and total use increased at an annual rate of

Storage facilities in Kansas provide a major service to the share of the regional market increased from 28 percent in

interstate pipeline systems that move natural gas to the 1990 to 30 percent in 1996.

Midwest Region, but they are also integral to regional requirements. For example, about 35 percent of the State's working Natural gas use still remains only a very small percentage of

gas storage capacity of approximately 109 Bcf is owned and the total energy used for electricity generation. While the

operated by Williams Natural Gas Company, which is installation of gas-fired generating capacity at utilities within

primarily a regional pipeline system. About 96 percent of the the region increased at an annual rate of 1.2 percent during

State's storage capacity is available to customers and shippers the first part of the decade, its share of the natural gas market

on other interstate trunklines, while the remaining 4 percent fell 1 percentage point and actual consumption fell by

is devoted to local distribution and production field service 4.3 percent per year (Table 12). One reason is that utilities in

(Appendix C, Table C1). About 41 percent of the daily peak- this region depend primarily on coal, which is generally

day storage deliverability in the State, or 960 million cubic available at a relatively low cost. However, local environfeet per day, is available to the two interstate pipeline mental needs, linked with technological constraints, could

companies traversing the region, Northern Natural Gas and have an impact on future development planning. Montana,

Panhandle Eastern Pipe Line Company. North Dakota, and Utah have some of the major coal basins

Storage facilities in the rest of the region serve primarily as

seasonal supply sources for local markets. Storage fields in Although the industrial sector has gained a larger share of

Utah provide service to shippers using the Questar Pipeline overall natural gas use in the region, the residential sector 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 consumption in the region, about 3.8 percent

through the Colorado Interstate Gas Company system. annually from 1990 through 1995, along with the growth in

End-Use Consumption

Within the region, natural gas has gained a slightly larger

share of the energy marketplace since 1990, rising

1 percentage point to 24 percent (Table 11). Consumption

increased at an annual rate of 3.8 percent from 1990 through

1996, while total energy production rose at a 2.1 percent rate. In 1997, eight pipeline expansion projects were completed in

In every State in the region, natural gas experienced a growth the Central Region, the largest of which was the new Pony

in market share, with North and South Dakota and Utah Express line owned and operated by KN Interstate Pipeline

having the largest increase. In each of these States, access to Company (Appendix B, Table B1). The new line runs from 75

greater local production was a major contributing factor. southern Wyoming to the Kansas City, Missouri, area and

Also, the ratio of State production to consumption at helps alleviate some of the capacity restraint problems

least doubled in each State compared with that in 1990 experienced by Rocky Mountain producers in recent years.

(Appendix C, Table C2). Greater consumption of local Also completed were the Trailblazer system expansion and

supplies was supported in part by low prices brought on by several area expansions by Colorado Interstate Pipeline 76

an inability by producers to ship their gas elsewhere because Company that addressed the same constraint problems and

of capacity limitations on several of the longhaul trunklines expanded the flow of area gas toward the Midwest.

exiting the region.

4.6 percent (Table 12). Reflecting this, the industrial sector’s

in the United States.

regional pipeline average utilization rates, from 57 percent in

1990 to 70 percent in 1996 (Table 9), would seem to indicate

the need for some expansion in the near future. There are

signs that some actions are already being taken in this regard.

Recent and Proposed Expansions

While completion of these projects helped resolve some

production-side demands for capacity, consumer demands in

the area have spurred several additional expansion proposals

(Appendix B, Table B2). Growth in the Denver, Colorado,

metropolitan area, for instance, has generated similar

proposals from two of the area’s largest systems: KN

Energy Information Administration, Capacity and Service on the 75

Interstate Natural Gas Pipeline System, 1990: Profiles and Analyses,

DOE/EIA-0556 (Washington, DC, June 1992), Table 16, p. 47.

Energy Information Administration, Natural Gas 1996: Issues and 76

Trends, DOE/EIA-0560(96) (Washington, DC, December 1996), Chapter 5.
Energy Information Administration 

60 Deliverability on the Interstate Natural Gas Pipeline System

Interstate Pipeline Company and Public Service Company of pipelines (Crossroads and Bluewater) were constructed in the

Colorado. The proposals call for developing new lines and region (Figure 10, Chapter 3), and a number of expansion

expanding old ones to bring expanding northern Wyoming projects were completed. The primary expansions included

gas production to the Denver area. The principal question is additions to the Great Lakes Transmission System (a 41-

whether both projects, as currently designed, will be percent increase in capacity), the Northern Border Pipeline

competitive and nonduplicative enough to be built. (36 percent), and ANR Pipeline Company (18 percent in

Midwestern Regional Market

The Midwest Region is the Nation's second largest market for

natural gas and is served by an extensive regional pipeline

network (Table 11). The region is weather-sensitive, with cold

winters and moderate summers. Minnesota and Wisconsin are

among the coldest States in the Nation, while the other four

States in the region are colder than the national average

(Table 10). The region also has a number of major population

centers and is the third largest of the six regions in population.

The large number of residential space-heating customers,

combined with the cold winters, result in large residential

requirements for natural gas. Yet, the region’s geographic

position between the Central and Northeast regions has

resulted in a significant portion of the region’s pipeline

system capabilities being reserved for deliveries beyond its

borders.

The region’s two northernmost States, Wisconsin and

Minnesota, as well as portions of Michigan, are served by

pipelines importing Canadian supplies, while the southern

portion of the region is served primarily by major trunklines

coming from the Southwest. Regional production, principally

from Ohio and Michigan, provides a little more than 8 percent

of the gas consumed in the region (Table 11).

The Midwest Region also has the largest amount of

underground storage capacity and daily deliverability from

storage of any region, more than 30 percent each of the U.S.

total. Regional LDCs control about 61 percent of daily

deliverability, more than any region but the Western.

Entering/Exiting Capacity

Today 18 interstate pipeline companies have the capacity to

move 24.8 Bcf of gas into the Midwest per day (Appendix A,

Table A2). The total capacity of the interstate pipeline

companies entering the region is more than for any other

region. Of that amount, 35 percent enters through Illinois,

26 percent through Ohio, 23 percent through Minnesota, and

the remainder through Indiana (Figure 15).

Capacity additions into the Midwest Region from 1991

through 1996 totaled 2.0 Bcf per day, an increase of 9 percent

over 1990 levels (Table 9). Two new major interstate

Michigan and Indiana). 

Regional peak-day deliveries by the interstate pipelines on

behalf of shippers approximated 19.8 Bcf per day during the

1996-97 heating season, which is equivalent to about

80 percent of the capacity into the region (Figure 15). When

deliveries to other interconnecting interstate pipelines are

included, the peak-day total is equivalent to 99 percent of

capacity. Although some demand is satisfied through

intraregional production and deliveries, the vast majority of

natural gas service in the region is dependent on the interstate

system.

In 1996, utilization of total capacity entering the region was

78 percent (Table 9), the second highest of the gas-importing

regions. This is a dramatic change from 1990, when the

utilization rate was the second lowest. Natural Gas Pipeline

Company of America has about 14 percent of the total

throughput capacity into the Midwest, primarily with

connections into Illinois (Appendix A, Table A2). Other

major players are: Texas Eastern Transmission Corporation

with 10 percent, and ANR Pipeline Company and Trunkline

Pipeline Company with 8 percent each. Texas Eastern

Transmission Corporation moves most of its gas through to

markets in the Northeast. On the other hand, almost all of the

contract commitments of the other companies represent commitments for deliveries within the Midwest market only.

On pipelines entering the region from Canada, the average

daily utilization rate in 1996 was 85 percent (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 percent and 78 percent, respectively. 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 balancing need.

Deliverability Within the Region

Nine of the interstate pipeline companies entering the

Midwest terminate and deliver most of their gas for shippers

within the region (Figure 15). For instance, ANR Pipeline

Company operates in all States in the region except

Minnesota and can import 2.0 Bcf per day into the region. In

1996, it had a systemwide average flow rate of about

70 percent. But the largest regional pipeline is Natural Gas
ND

2,799

1,655 1,575

1,370

SD

Central

Region

2,354

63

2,679

84

1,799

9,879

KY

MO

695

3,901

70

2,225

550

4,568

2,953

IA

2,480

735

1,708

1,417

4,990

1,944

2,209

3,560

4,462

468

1,792

2,135

2,752

WV

250

3,049

1,573

Southeast

Region

9,821

PA

465

2,543

Canada

Northeast

Region

4,887

2,038

Leaving: 9,784 

Entering: 24,787 

Estimated Total Throughput Capacity

Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 61

Figure 15. Interstate Natural Gas Capacity Summary for the Midwest Region, 1996

(Volumes in Million Cubic Feet per Day)

Principal Interstate Natural Gas Pipeline Companies Operating in the Midwest Region

Regional Service Level Systemwide Utilization Rates %1

Principal Market Region / Supply System Peak-day Delivery Intercon- 12-Month Peak Summer

Pipeline Name Source(s) Configuration Deliveries Points nects Average Day Offpeak

Regional Secondary System of of

Primary/ Percent of Number Number

2 3 45 6

Regional Pipelines

ANR Pipeline Co SW Trunk 79 259 10 70 100 66

Crossroads Pipeline Co SW Trunk 100 NA 1 NA NA NA

Great Lakes Gas Transmission Co Canada Trunk 100 206 14 94 132 59

Midwestern Gas Transmissions Co SW Trunk 94 18 6 89 104 80

Natural Gas Pipeline Co of America SW Trunk 75 165 4 84 96 80

Panhandle Eastern Pipeline Co SW Trunk 88 67 3 78 98 58

Texas Gas Transmission Corp SW Trunk 28 103 5 79 111 58

Trunkline Gas Co SW Trunk 67 53 6 74 90 66

Viking Gas Transmission Co Canada Trunk 97 39 4 94 105 82

Supplemental Pipeline Service

Columbia Gas Transmission Corp SW, NE Grid 38 121 1 73 98 26

CNG Transmission Corp SW, NE Grid 13 15 0 80 92 25

Mississippi River Transmission Co SW Trunk 39 13 0 85 92 59

Northern Natural Gas Co SW, Canada Trunk/Grid 56 129 2 92 107 80

Tennessee Gas Pipeline Co SW Trunk 4 6 7 90 111 70

Texas Eastern Transmission Co SW Trunk 1 50 12 84 109 49

Usage rates are based upon capacity and transportation volumes for the whole system and do not represent regional service only. 1

"Trunk” systems are long-distance trunklines that generally tie supply areas to market areas. “Grid” systems are usually a network of many interconnections and 2

delivery points that operate in and serve major market areas. Some systems are a combination of the two.

Represents the percent of total pipeline system volume delivered within the region on the system peak-day occurring in the 1996-97 heating year. 3

Represents total system capacity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 4

Represents total system capacity divided by the single peak-day volumes delivered in the 1996-97 heating year as reported in FERC Form 2. 5

Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based on 6

FERC Form 11 gas delivery data for 1995) divided by 153 days. April and October are considered to be months that “shoulder” the heating season of November-March.

NA = Not available.

Sources: Capacity: Federal Energy Regulatory Commission, FERC 567 Capacity Report, “System Flow Diagram” and Annual Capacity Report (18 CFR §284.12);

Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity, as of December 1997. 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.”
Energy Information Administration 

62 Deliverability on the Interstate Natural Gas Pipeline System

Pipeline Company of America, with 3.3 Bcf per day. In 1996, Michigan and Illinois have the largest number of gas storage

its average daily usage rate within the region was 84 percent. facilities in the region. Their combined working gas storage

However, Natural Gas Pipeline Company of America is capacity in 1996 was approximately 0.9 trillion cubic feet, or

second to ANR Pipeline in the amount of regional peak 78 percent of the total regional storage capacity (Appendix C,

deliveries (almost all in Illinois). Table C1). This represents a peak-day deliverability rate of

Those pipeline systems involved in extensive trade with 71 percent 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 Public Service

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 percent. working gas storage (the excess) to support shippers using its

In contrast to utilization rates on lines entering the region or

moving gas to the Northeast, intraregional utilization rates Great Lakes Gas Transmission and ANR Pipeline companies

averaged only 53 percent in 1996. This is the combined use Michigan storage facilities extensively to support their

average utilization of all flows from one State within the shippers needs. In the first case, the Great Lakes system

region to another. This statistic, combined 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 Michigan storage sites to store

Midwest in 1990, seems to indicate that most pipeline supplies shipped for Canadian customers during the

companies have sufficient throughput capacity to summer for redelivery during winter peak periods. ANR

accommodate any additional demand for natural gas in the provides essentially the same service but for domestic

near term. shippers who need to supply customers throughout the

A relatively few large shippers account for the bulk of the gas high load factors on these systems during the summer months.

delivered by interstate pipeline companies within the region.

In Illinois and Ohio, the demands of the two largest LDCs Because of the region’s relatively cold and volatile weather,

represent 47 and 55 percent, respectively, of the total LDCs in this market also have come to rely on LNG peaking

interstate system volumes delivered in each State and the facilities to supplement or substitute for unavailable local

equivalent of 25 and 30 percent, respectively, of the total underground storage capacity. The Midwest is the third

capacity entering those States. largest source of LNG storage, with about 18 Bcf of storage 77

In Illinois and Indiana, the largest LDCs each interconnect

with at least three major pipeline systems, providing

flexibility in their purchase and transportation strategies. On

the other hand, in Minnesota, the major LDCs acquire gas

from only one interstate pipeline company, Northern Natural

Gas. 

Storage Deliverability

The Midwest has the highest level of working gas storage high as 31 percent of overall consumption (Appendix C,

capacity of any region, 1.1 trillion cubic feet (Table 10). Table C2).

During the 1996-97 heating season, storage withdrawals in

this region averaged 2.0 Bcf per day, with much greater levels Natural gas consumption in the region increased at an annual

on peak days (approximately 3.8 Bcf). rate of 2.9 percent from 1990 through 1995. All customer 78

18 Bcf, or 77 percent of the area's capability. In Illinois,

Chicago market center. 

Midwest during peak periods. These activities help maintain

capacity and 2.7 Bcf of peak-day deliverability.

End-Use Consumption

Natural gas usage accounts for about 25 percent of overall

energy consumption in the Midwest, which is second only to

the 39 percent level in the Southwest Region, the major U.S.

production area (Table 11). Since 1990, the natural gas share

in the region increased by 1 percent. The levels in the

individual States of the region range from 21 percent to as

sectors showed an increase, but a major contributor to this

gain has been the growth in the use of natural gas by electric

utilities within the region (Table 12). Although electric

utilities account for only 2 percent of regional natural gas

consumption, the amount of electric generating capacity fired

by natural gas grew at an annual rate of 8 percent, while the

number of gas-fired units increased at an annual rate of

0.3 percent during the period (Table 13).

Derived from data reported to the Energy Information Administration on 77

Form EIA-176, “Annual Report of Natural and Supplemental Gas Supply and

Disposition,” and the EIAGIS-NG Geographic Information System, Natural

Gas Pipeline State Border Capacity, as of December 1997.

Energy Information Administration, Form EIA-191, “Monthly 78

Underground Gas Storage Report.”
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 63

Although the region's population base grew by only 3 percent

during the 1980s (the smallest increase of the six regions) and

1.2 percent annually in the early 1990s (Table 11), residential

consumption of natural gas in the region increased at an

annual rate of 3.7 percent between 1990 and 1996. This

growth was second only to the increase in this sector in the

Southeast Region (Table 12). The cold winters in the Midwest

account for the residential sector using 40 percent of the

natural gas delivered to the region each year (up 1 percentage

point since 1990). The number of residential customers in the

region increased during the period as did the average use per

customer (Table 13). 

Industrial sector consumption increased at a 3.4 percent

annual rate as well, although its share of the regional natural

gas market fell slightly (Table 12). There had been some

speculation that industrial gas demand in the Midwest would

decrease because of a trend toward greater service industry

development, displacing heavy industries that tend to be

greater users of natural gas, but the average use per industrial

customer actually increased at an annual rate of 2.6 percent.

The number of industrial customers grew slightly during the

period.

Recent market patterns suggest that natural gas demand in the

Midwest will continue to increase into the next century but

probably at a slower rate than demand growth in some of the

regions. Although major plans are underway to increase

deliverability to the Chicago market area, it is likely that

much of that capacity will be forwarded to the Northeast.

Recent and Proposed Expansions

Three pipeline expansion projects into the Midwest Region

were completed during 1997, providing 441 million cubic feet

per day of additional interstate service (Appendix B). Only

one of these projects, the ANR Michigan Leg expansion,

affected the major Chicago market. The other two provide

additional service to growing markets in Wisconsin and

Minnesota.

Several large new pipelines and major expansion projects into

the region have been proposed, primarily to transport

Canadian natural gas from expanding production fields in

Alberta and British Columbia to the Chicago area. What is

noteworthy about this effort is that the ultimate market for

much of this new capacity will be beyond the region, in

eastern Canada and the U.S. Northeast. Indeed, if these

projects were targeted only toward gaining market share

within the Midwest Region, an excess of capacity would

develop over the next several years. Planned capacity

expansion from the Southwest, which remains the largest

source of Midwest market gas supply, is minimal. 

Northeast Regional Market

The Northeast consumes more energy than any other region,

although only 21 percent (up 3 percent since 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 source of natural gas and, as a result,

a large distribution network of pipelines has been in place for

many years. Similarly, the region has considerable access to

underground storage since gas storage fields were first

developed and used commercially in the area. Still, the New

England States have only truly had access to natural gas

supplies since the 1950s.

The region has large swings in gas demand because of

weather. Overall, it is the third coldest of the regions

(Table 10), with some of the coldest States in the Nation at its

northern limits. Withdrawals from storage are necessary to

meet peak demand, as total capacity entering the region plus

regional gas production are only about two-thirds of the

region's peak demand.

Residential and commercial natural gas consumption (mostly

space-heating demand) accounts for the largest share of the

regional natural gas market although the industrial and

electric utility sectors also represent large users of natural gas,

with 31 and 8 percent, respectively (Table 12). The major

markets in the region are the metropolitan areas of Boston,

Massachusetts; New York City; Philadelphia/Trenton;

Baltimore/Washington; Richmond, Virginia; and the corridor

from Erie, Pennsylvania, to Buffalo, New York.

Entering/Exiting Capacity

Today the interstate pipeline companies serving the Northeast

have access to supplies from all major domestic

gas-producing 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). Much of this capacity moves within

the region toward New York City and Boston. In 1996, the

interstate pipeline system had the capacity to move

approximately 5 Bcf per day along routes coming out of both

the Southeast and Midwest regions. In addition, limited

amounts of liquefied natural gas (LNG) is imported into

Massachusetts from the Middle East.

Transportation capacity into the Northeast increased by more

than 2.4 Bcf per day (24 percent) between 1990 and 1996

(Table 9), second only to the increase in the Western Region.

Most of this new capacity provided greater access to

Canadian supplies. Some of the larger projects included

completion of the Empire Pipeline (0.5 Bcf per day), which
4,887

TN

2,536

Midwest 

Region

KY

26

2,752

2,038

OH

NC

2,135

75

1,943

465

4,589

649

3,213

21

2,587

445

2,256

603

307

4

Canada

2,393

5,981

382

2,730

1,571

2,322

10

28

141

1,059

31

1,900

250

Southeast

Region

80

81

2,975

5,149

520

31

31

71

106

560

318

760

Maryland

Delaware

 West

Virginia

Virginia

Connecticut

New Jersey

New York

Rhode Island

Massachusetts

New Hampshire

Pennsylvania

Vermont

Maine

Leaving: 2,558 

Entering: 12,429 

Estimated Total Throughput Capacity

350

Energy Information Administration 

64 Deliverability on the Interstate Natural Gas Pipeline System

Figure 16. Interstate Natural Gas Capacity Summary for the Northeast Region, 1996

(Volumes in Million Cubic Feet per Day)

Principal Interstate Natural Gas Pipeline Companies Operating in the Northeast Region

Regional Service Level Systemwide Utilization Rates %1

Principal Market Region / Supply System Peak-day Delivery Intercon- 12-Month Peak Summer

Pipeline Name Source(s) Configuration Deliveries Points nects Average Day Offpeak

Regional Secondary System of of

Primary/ Percent of Number Number

2 3 45 6

Regional Pipelines

Algonquin Gas Transmission Co SW Trunk/Grid 100 97 5 72 89 45

CNG Transmission Corp SW, NE Grid 87 110 25 80 92 25

Columbia Gas Transmission Co SW, NE Grid 51 293 16 73 98 26

Eastern Shore Natural Gas Co SW Grid/Trunk 100 NA NA NA NA NA

Equitrans Inc SW, NE Grid 100 132 10 70 78 23

Granite State Gas Transmission Co Canada Grid/Trunk 100 NA NA NA NA NA

Iroquois Gas Transmission Co Canada Trunk 100 10 4 102 122 99

National Fuel Gas Supply Corp SW, Canada Grid/Trunk 100 98 3 75 92 29

Tennessee Gas Pipeline Co SW, Canada Trunk 55 116 51 90 111 70

Texas Eastern Transmission Corp SW Trunk 88 69 18 84 109 49

Transcontinental Gas Pipeline Co SW Trunk 69 124 10 83 99 81

Vermont Gas Systems Inc Canada Trunk 100 NA NA NA NA NA

Supplemental Pipeline Service

East Tennessee Natural Gas Co SW Trunk/Grid 8 25 0 84 88 37

Usage rates are based upon capacity and transportation volumes for the whole system and do not represent regional service only. 1

"Trunk” systems are long-distance trunklines that generally tie supply areas to market areas. “Grid” systems are usually a network of many interconnections and 2

delivery points that operate in and serve major market areas. Some systems are a combination of the two.

Represents the percent of total pipeline system volume delivered within the region on the system peak-day occurring in the 1996-97 heating year. 3

Represents total system capacity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 4

Represents total system capacity divided by the single peak-day volumes delivered in the 1996-97 heating year as reported in FERC Form 2. 5

Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based on 6

FERC Form 11 gas delivery data for 1995) divided by 153 days. April and October are considered to be months that “shoulder” the heating season of November-March.

NA = Not available.

Sources: Capacity: Federal Energy Regulatory Commission, FERC 567 Capacity Report, “System Flow Diagram” and Annual Capacity Report (18 CFR §284.12);

Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity, as of December 1997. 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.”
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 65

is an intrastate affiliated with ANR Pipeline Company, the addition, each company has access to numerous underground

Iroquois Pipeline (0.9 Bcf per day), and Tennessee Gas storage facilities, allowing their shipper/customers to develop

Pipeline Company’s expansion of its Niagara import facilities inventories of seasonal gas supplies for winter use.

(by 0.5 Bcf per day).

In addition, several interstate pipelines serving the region largest LDCs in the region, many of which are affiliates. From

were significantly expanded. The largest expansion was on 1990 through 1996, Columbia added between 150 to

the Texas Eastern Pipeline system (0.5 Bcf per day) serving 200 MMcf per day of capacity and CNG added about

Pennsylvania, New York, and New Jersey, as well as southern 100 MMcf to their systems. The primary expansion

New England through service to its affiliate, Algonquin Gas motivation in these two cases was to attract additional

Transmission Company (which itself added about 122 million customers and improve overall service in the region.

cubic feet (MMcf) per day of capacity). Transcontinental Gas

Pipeline Company, a major supplier to the region, Utilization rates tend to be much lower on the more disperse,

added approximately 165 MMcf per day in the grid-type pipeline systems, such as CNG and Columbia Gas

Pennsylvania/New York area to improve its local capabilities. Transmission. Grid systems function as distribution

Its larger contribution to regional service, however, was a companies to the LDCs as well as transmission companies.

major expansion in the Virginia/North Carolina area where The capacity to supply gas in one portion of the grid depends

more than 420 MMcf per day was added (1993). The latter upon how much is being supplied out of the system by other

project coincided with improvements along much of the portions of the grid. Both CNG and Columbia Gas

Transco system extending from Louisiana to Virginia. Transmission have multiple lines crossing the State borders

About three-quarters of the capacity 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 Kentucky

Transcontinental Gas Pipe Line Corporation, Texas Eastern border, where it receives Gulf-of-Mexico 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 percent. part of the grid and operated at an average utilization rate of

Tennessee Gas Pipeline had the highest utilization about 31 percent in 1996.

(90 percent) and the highest actual volume (2.8 Bcf per day)

into the region (Appendix A, Table A3). The flow of gas out of the region is almost exclusively 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 commitments 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 capacity in the region (Appendix C,

Table C1), as well as some of the largest entering and exiting

capacities and annual flow rates (Appendix A, Table A3).

More pipeline capacity exits these States than enters,

reflecting their major storage capability as a seasonal supply

source for the States north and east.

The largest major regional pipeline companies, CNG

Transmission and Columbia Gas Transmission, have an

extensive infrastructure and network of local delivery points

and pipeline interconnections. They also have a number of

receipt points, where they bring in local production sources to

augment supplies from the Southwest and Canada. In

Both companies are also the major suppliers of some of the

within the region, allowing gas to flow in both directions at

Midwest (although some lines have bidirectional service) over

the many lines that were built around the turn of the century

to move local production. West Virginia, western

Pennsylvania, and southwestern New York were once the

region’s and the Nation’s largest producing areas and,

consequently, have many local gathering, distribution, and

storage interconnections. These areas also have many

interconnections with operations in Ohio, which is the reason

for the 2.0 Bcf per day of capacity exiting the region to the

Midwest.

In addition to the interstate pipeline companies that bring gas

into the region from the Midwest and Southeast, several

smaller interstate pipeline companies operate totally within

the region (Figure 16). Foremost among these is Algonquin

Gas Transmission Company, which has the capacity to move

1.2 Bcf per day from New Jersey into New York

(Appendix A, Table A3). During the 1996-97 heating season,

peak-day deliveries for its entire system totaled about

1.5 million cubic feet. Algonquin, with 1,056 miles of trunk

transmission lines, distributes the gas received in New Jersey

to New York, Connecticut, Rhode Island, and Massachusetts.
Energy Information Administration 

66 Deliverability on the Interstate Natural Gas Pipeline System

The remaining small interstate pipeline companies averaged annual growth in natural gas demand in the region grew at a

only 32 MMcf per day of interstate transmission in 1996. faster rate than the growth in overall energy use, 4.9 percent 79

Storage Deliverability

Many of the depleted gas fields in New York, Pennsylvania,

and West Virginia are now used for storage, which is essential

for balancing gas supplies for the region (Table 10). Interstate

capacity into the region, 12.4 Bcf per day, combined with

local production (approximately 1 Bcf per day on average in

1996) is the equivalent of only about two-thirds of the peakday requirements within the region. The difference between

this available system capacity and shipper and consumer

demand is designed to be met by withdrawals from storage.

During the 1996-97 heating season, average daily

withdrawals in the region were about 4.9 Bcf; during January

1997, the month with the highest average, storage

deliverability averaged 7.7 Bcf per day.80

The growth in the Northeast market has also spurred

numerous storage projects. Plans are underway to increase

storage deliverability in the region 17 percent by 2000; this

would include new installations or expansions at 37 or more

of the 121 storage sites in the region. Almost all of the 81

expansions would be at 35 sites owned and operated by

Columbia Gas Transmission Company. LNG storage is also

being increased in the New England market to provide

peaking support to those LDCs that will be receiving supplies

along new pipeline routes which are not convenient to

underground storage facilities.

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 Bcf per day, is

32 percent as large as the total daily deliverability from

underground storage facilities. This backup capability has

been included in the overall design of the regional network

and is necessary to meet the rapid increases in demand that

can occur because of sudden temperature changes.

End-Use Consumption

Although the Northeast has the highest energy consumption

of the regions, natural gas is a relatively low proportion of

total energy consumed: 21 percent versus a national average

of about 24 percent (Table 11). Yet, since 1990, the average

versus 1.2 percent (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 can be attributed to the industrial sector,

where natural gas consumption grew at an annual rate of

8.3 percent (Table 12) while per-customer usage grew at a

9.7 percent rate (Table 13). Reflected in these rates were large

increases in industrial use in New York and New Jersey

(Appendix C, Table C3). The increase in industrial gas use

came despite a 1.5 percent per annum drop in the industrial

customer base during the period.

Electric utilities in the region had a decrease in natural gas

use, which declined at an average annual rate of 4.7 percent

during the period. This occurred in spite of a growth in gaspowered generating capacity in the region. While the number

of gas-fired electric generating units in the Northeast

(excluding industrial cogeneration capacity) increased by only

0.4 percent per annum, generating capacity grew at a

4.4 percent annual rate (Table 13). Currently, about

14 percent of the generating capacity in the region is gas-fired

and, coincidently, gas-fired generating capacity in the region

also represents 14 percent of total U.S. gas-fired generating

capacity.82

Although industrial use of natural gas continues to grow,

residential customers in the region still remain the primary

users of natural gas. They accounted for 35 percent of the gas

consumed in the region in 1996, in contrast to the national

average of 24 percent. Although the population of the region

is estimated to have increased by only 0.7 percent per annum

(Table 11) between 1990 and 1996, total gas consumption in

the region increased at a 4.9 percent rate. Space-heating gas

demand in the region is driven by the growing, highly

populated urban corridor that stretches from Boston,

Massachusetts, to Richmond, Virginia.

Recent and Proposed Expansions

In 1997, 12 expansion projects were completed in the

Northeast, increasing overall deliverability within the region

by more than 772 million cubic feet per day (Appendix B,

Table B1). Only one project brought additional gas into the

region; the rest were implemented to improve local

deliverability to expanding markets within the region.

Numerous other projects have been proposed for the

Northeast market that could increase capacity by more than

Federal Energy Regulatory Commission, FERC Form 2 and 2A, “Annual 79

Report of Natural Gas Companies,” 1996.

Energy Information Administration, Form EIA-191, “Underground Gas 80

Storage Report.”

Energy Information Administration, “U.S. Underground Storage of 81

Natural Gas in 1997: Existing and Proposed,” Natural Gas Monthly, Derived from: Energy Information Administration, Form EIA-860,

DOE/EIA-0130(97)/9) (Washington, DC, September 1997) “Annual Electric Generator Report” (1990-1996).

82
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 67

7 Bcf per day. Planned expansions into the region would total Capacity into the Southeast Region grew by slightly more

4.0 Bcf per day, or 32 percent above the 1996 level. than 7 percent between 1990 and 1996 (Table 9). Most

Increasing demand for natural gas service in the region and capacity additions occurred within the region. The major

the readiness of Canadian producers to meet the need underlie projects completed were the Florida Gas Transmission

the bulk of the expansions. Long dependent on fuel oil, the expansion, the Mobile Bay Pipeline, and the Transcontinental

Northeast has seen a steady increase in the availability of Gas Pipeline southern expansion. Noteworthy were the

natural gas in recent years. additional pipeline expansions serving the northern North

While a large portion of the anticipated growth in natural gas (Columbia Gas Transmission and Transcontinental Gas

demand is expected to come from increased usage by the Pipeline Company) extended their systems into the Southeast

industrial sector, the major growth market is expected to be market in 1993.

the electric utility sector. Several nuclear generating stations

in the region are slated for retirement during the next several More natural gas pipeline capacity (excluding offshore-toyears and will be replaced by nonnuclear plants. The natural onshore) enters and exits Mississippi than any other State in

gas pipeline industry believes that many of these replacement the Nation (Appendix A, Table A4). It is the hub State for

facilities, as well as a number of new conventional capacity into the region, with 21.3 Bcf per day coming into

power plants, will be built during the next decade and will use the State and 20.5 Bcf per day leaving the State. While

high-efficiency natural-gas-turbine technology more widely. several routes flow southward toward Florida, most are

At the same time electricity demand in the region is expected directed to the Northeast and Midwest regions (Appendix A,

to grow as the effects of electric industry deregulation widen Figure A4).

competition in the market.

Southeast Regional Market

The Southeast Region is the least developed market for

natural gas in terms of per-capita consumption. In fact, natural

gas accounts for only a small percentage of the total energy

consumed in the region (Table 11). However, because of its

proximity to major producing areas in the Southwest,

numerous interstate natural gas pipeline companies operate

throughout the region (Appendix A, Figure A4), transporting

significant volumes via the region to the Northeast and

Midwest markets.

Although the region has only limited storage capacity,

numerous high-deliverability storage sites exist in the

southern part of the region, many of which have been

developed since 1990. Four such sites were added in

Mississippi, which 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 services needed by shippers with high

upstream demand swings and load balancing requirements.

Entering/Exiting Capacity

During peak periods, the interstate pipeline system has the

capacity to move up to 21.4 Bcf into the Southeast Region,

principally from the Southwest (Figure 17). This is the

second-largest capacity level into any region. More than

70 percent of this capacity is redirected out of the region, with

9.8 Bcf per day into the Midwest and 5.1 Bcf per day into the

Northeast Region.

Carolina market. Several pipelines from the Northeast Region

Fifteen interstate pipeline companies operate within the

region, with all but four transporting gas from the Southwest.

By capacity level, the largest transporters are Tennessee Gas

Pipeline Company, Transcontinental Gas Pipe Line Corporation, Texas Eastern Transmission Corporation, and Texas

Gas Transmission Corporation. These same four are also the

largest exporters.

On its system peak day in 1995, Tennessee Gas Pipeline

transported only about 30 percent of its volumes to delivery

and interconnection points in the Southeast Region.83

Likewise, Transcontinental Gas Pipe Line, which traverses the

region via the Carolinas, delivered only 33 percent of its

peak-day volumes in the Southeast. In 1996, average

utilization rates on Transcontinental's lines en route to the

weather-sensitive Northeast were 83 percent in Mississippi

and 79 percent out of Virginia (Appendix A, Table A4). The

average daily flow of natural gas into Mississippi in 1996

averaged 16.1 Bcf: 10.9 Bcf from Louisiana, at 79 percent of

capacity, and 5.1 Bcf from Arkansas at 73 percent of capacity.

The combined utilization on lines entering Mississippi in

1996 was 77 percent.

Major shippers on the major interstate pipeline systems

serving the region have peak-day demands of approximately

9.4 Bcf per day. Within the region, demand requirements are

the largest in Tennessee, primarily because of the

interconnections and service provided among several

interstate pipeline companies rather than service to LDCs.

Based on coincidental peak-day deliveries reported on the annual FERC 83

System Flow Format 567 report.
Southwest

Region

20,846

Midwest

Region

13,821

AR

LA

11,269

9,821

IL

MO

405

9,342

1,799

25

7,026

275 600

3,559

IN

12,343

25

26

20

3,471

5,129

1,620 56

3,883

200

OH

4,462

62

2,587

2,361

WV

75

50

56

3,002

5,149

VA

445

Northeast

Region 520

North 

Carolina

Kentucky

South 

Carolina

Georgia

Florida

Tennessee

Alabama

Mississippi

Leaving: 15,375 

Estimated Total Throughput Capacity

Entering: 21,366 (excludes Gulf of Mexico) 

Energy Information Administration 

68 Deliverability on the Interstate Natural Gas Pipeline System

Figure 17. Interstate Natural Gas Capacity Summary for the Southeast Region, 1996

(Volumes in Million Cubic Feet per Day)

Principal Interstate Natural Gas Pipeline Companies Operating in the Southeast Region

Regional Service Level Systemwide Utilization Rates %1

 Regional Secondary System of of

Principal Market Region / Supply System Peak-day Delivery Intercon- 12-Month Peak Summer

Pipeline Name Source(s) Configuration Deliveries Points nects Average Day Offpeak

Primary/ Percent of Number Number

2 3 45 6

Regional Pipelines

Columbia Gulf Transmission Co SW Trunk 98 5 3 98 101 96

East Tennessee Natural Gas Co SW Grid/Trunk 92 122 2 84 88 37

Florida Gas Transmission Co SW Trunk 92 181 3 71 102 66

Midcoast Pipeline Co SW Trunk/Grid 100 NA NA NA NA NA

South Georgia Natural Gas Co SW Grid 100 68 1 NA NA NA

Southern Natural Gas Co SW Grid/Trunk 93 323 7 66 100 88

Texas Gas Transmission Co SW Trunk 55 215 2 79 111 58

Supplemental Pipeline Service

ANR Pipeline Co SW Trunk/Grid 1 6 1 70 100 66

Columbia Gas Transmission Corp SW, NE Grid 11 50 2 73 98 26

Koch Gateway Pipeline Co SW, SE Grid/Trunk 25 365 4 57 100 59

Midwestern Gas Transmission Co SW Trunk 6 3 1 89 104 80

Tennessee Gas Pipeline Co SW, Canada Trunk 30 117 22 90 111 70

Texas Eastern Transmission Corp SW Trunk 4 37 3 84 109 49

Transcontinental Gas Pipeline Co SW Trunk 33 117 2 83 99 81 8

Trunkline Gas Co SW Trunk 12 24 3 74 90 66

Usage rates are based upon capacity and transportation volumes for the whole system and do not represent regional service only. 1

"Trunk” systems are long-distance trunklines that generally tie supply areas to market areas. “Grid” systems are usually a network of many interconnections and 2

delivery points that operate in and serve major market areas. Some systems are a combination of the two.

Represents the percent of total pipeline system volume delivered within the region on the system peak-day occurring in the 1996-97 heating year. 3

Represents total system capacity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 4

Represents total system capacity divided by the single peak-day volumes delivered in the 1996-97 heating year as reported in FERC Form 2. 5

Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based 6

on FERC Form 11 gas delivery data for 1995) divided by 153 days. April and October are considered to be months that “shoulder” the heating season of NovemberMarch.

NA = Not available.

Sources: Capacity: Federal Energy Regulatory Commission, FERC 567 Capacity Report, “System Flow Diagram” and Annual Capacity Report (18 CFR §284.12);

Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity, as of December 1997. 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.”
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 69

Deliverability Within the Region

Local gas service within the region, for the most part, is

characterized by the presence of a large number of

distributors per State, although in most States only one or two

large companies predominate. For example, while Georgia

has 90 LDCs, the largest one, Atlanta Gas Light Company,

represents nearly three-quarters of the total commitments on

interstate pipeline capacity 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 exceptions to this

regional pattern of having many different pipeline customers.

Each of these States has fewer than 25 LDCs, most of which

are quite small—representing less than 15 percent of peak-day

deliveries on the interstate systems serving the respective

States. The Carolinas were not served by any interstate natural

gas pipeline until after World War II. Most of the interstate

pipeline service (more than two-thirds) in North Carolina and

South Carolina is from Transcontinental Gas Pipe Line

Corporation. Southern Natural Gas Company also supplies

customers in South Carolina.

The largest peak-day delivery volume in the region is 1.7 Bcf

per day by Columbia Gulf Transmission Corporation to its

affiliate, Columbia Gas Transmission Company, in Kentucky. Economic growth in recent years has led to increased natural

Columbia Gas of Kentucky, an LDC, in turn receives about gas use in the Southeast marketplace. Natural gas increased its

0.2 Bcf per day of that total from Columbia Gas Transmission share of the energy market, outpacing the growth in total

Corporation. Louisville Gas & Electric Company and Western energy usage, 2.9 percent per year versus 2.2 percent

Kentucky Gas Company are the largest LDCs in Kentucky. (Table 11). Reflecting this growth, in 1995, natural gas use in

Their shipments with Texas Gas Transmission Corporation the region stood at 15 percent of total energy used, 2 percent

account for about three-quarters of the pipeline company's greater than in 1990. Still, the Southeast remains the smallest

total deliverability within the State. consumer of natural gas of all the regions.

Storage Deliverability

Although the Southeast has the least underground storage capacity of the regions, it has the largest percentage of its daily

deliverability (47 percent) from high-deliverability storage

sites (Table 10), which are mainly located in Mississippi and

Alabama. These facilities are used primarily by shippers on

the interstate pipeline system to balance their loads on lines

crossing into Alabama and points north and east and to

accommodate the periodic swings in demand that are

characteristic of some industrial and electric utility users. In

Mississippi, interstate shippers and local consumers have

access to a delivery (withdrawal) capability equivalent to

2.2 Bcf per day from salt dome storage sites (Appendix C,

Table C1).

In the northwestern part of the region, in Kentucky, all of the

storage sites are conventional depleted reservoirs, which are

used primarily for seasonal supply and backup. About

32 percent of this underground storage capacity is owned by

LDCs that serve local markets in Louisville, Kentucky, and

Evansville, Indiana. Nevertheless, while most of the

remaining storage in Kentucky (representing about 67 percent

of the daily peak-day withdrawal capability in the State) is

owned by interstate operators, the bulk of its working gas

capacity and deliverability service is reserved by LDCs in

northern Kentucky, southern Ohio, Indiana, and Illinois.

Four-fifths of the storage capacity in Kentucky is owned by

one interstate pipeline company, Texas Gas Transmission

Corporation. The company's storage facilities have a total

estimated peak-day delivery rate of about 1.2 Bcf per day,

about 70 percent of the total within the State. This level is

equivalent to about 80 percent of the total daily capacity of

Texas Gas Transmission's lines moving north into Indiana.

These storage facilities are also in close proximity to the ANR

Pipeline Company system, which traverses the State to

Indiana and Michigan. Combined, Texas Gas Transmission

and ANR Pipeline have the capacity to move 2.9 Bcf per day

north to Indiana (Appendix A, Table A2); Texas Gas

Transmission's peak-day storage delivery level is the

equivalent of about 42 percent of that figure.

End-Use Consumption

Temperate weather, abundant regional coal reserves, and the

long history of electricity use fostered by the Tennessee

Valley Authority (TVA) have combined 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 increased

2 percentage points since 1990 because of an increased

number of customers during the period (Table 12). The States

with the largest residential natural gas markets in the region

are Georgia (33 percent) and Kentucky (30 percent)

(Appendix C, Table C3).

While the industrial sector increased its consumption of

natural gas at an annual rate of 3.2 percent between 1990 and

1996, its share within the natural gas market fell several

percentage points (Appendix C, Table C3). Nevertheless, this

sector currently represents 44 percent of the natural gas usage

within the region, the highest share for the industrial sector in

any region except the Southwest (Table 12). Average use by

industrial customers increased at an average annual rate of
Energy Information Administration 

70 Deliverability on the Interstate Natural Gas Pipeline System

almost 1.4 percent in the early 1990s (Table 13) after within the region also showing an increase over the past

declining throughout the latter part of the 1980s. several years (about 8 percentage points), increased expansion

The electric utility sector share also grew during the early

1990s as more gas-fired units were installed at electric

generating plants in the region. From 1990 through 1996, gasfired generating capacity grew at an annual rate of 4.2 percent

compared with a 1.2 percent growth rate in total generating

capacity installed. In 1996, gas-fired generating capacity

accounted for 10 percent of the total, compared with only

4 percent in 1990. Currently, this sector represents 16 percent

of the natural gas market in the region, up 1 percentage point

since 1990. Its share can be expected to increase during the

next several years, even if the annual growth rate slows from

the 8.3 percent pace during the period from 1990 through

1996. 

Recent and Proposed Expansions

The continuing decline in deliverability from the western Gulf

of Mexico and the increasing development of deep water

production in the eastern part of the Gulf (see Chapter 2) is

expected to result in greater capacity utilization on the major

trunklines traversing the Southeast Region. New capacity

could be needed in the near future, but, as of March 1998, no

major expansions have been submitted to FERC for approval.

Only Columbia Gulf Transmission Company (0.2 Bcf per

day) and Tennessee Gas Pipeline Company (0.2 Bcf per day)

have announced 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

customers and expanding into new market areas. In 1997, five

projects were completed, accounting for only 0.4 Bcf per day

of new capacity (Table ES1). This is equivalent to only about

0.5 percent of existing interstate pipeline capacity in the

region (Appendix B).

More than 3.2 Bcf of new capacity has been proposed within

the region for completion between 1998 and 2000

(Appendix B, Table B2). About 54 percent of this capacity is

to bring in supplies from the Gulf of Mexico. While almost all

of the onshore projects are regional, and for the most part

support the area’s expanding electric utility and industrial

sectors, the offshore projects 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 customer groups,

including electric utilities (Table 12). In fact, natural gas

demand in the region grew at an annual average rate of

3 percent between 1990 and 1995, with each customer

category showing an increase. With pipeline utilization rates

planning in the region can be expected.

Southwest Regional Market

Even though large volumes of natural gas leave the Southwest

Region for other regional markets, significant volumes still

remain in the region to fulfill a high level of industrial

demand encouraged over the years by the proximity to

production areas. In 1996, the Southwest Region consumed

more natural gas than any other region, one-half more than

the next largest consuming region, the Midwest. About onethird of the Nation's gas is consumed in the Southwest.

The region also has numerous underground storage reservoirs,

most of which are used to store excess natural gas production

during months of low consumption (Table 10). In recent

years, however, more storage in the region is being devoted

to supporting the needs of customers using natural gas market

centers in the area. Total working gas storage capacity

(983 Bcf) is the second highest of the regions. The region has

temperate winters and long, hot summers. Louisiana and

Texas are the second- and third-warmest States in the lower

48 States, which accounts for large electricity loads for

air-conditioning services.

Entering/Exiting Capacity

Because the Southwest Region has many of the largest gasproducing areas in North America, a huge amount of natural

gas pipeline capacity in the region represents export

capability. More than 35.7 Bcf per day of capacity exits the

region (Figure 18) on at least 20 interstate pipelines

(Appendix A, Figure A5), directed toward markets in all other

regions of the country, as well as Mexico. This represents an

8-percent increase since 1990 (Table 7, Chapter 3), most of

which 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

increased along each of the exiting corridors except into the

Western Region (and Mexico). The installation of excess

interstate pipeline capacity, coupled with an economic

downturn in that region, brought on a sizable drop in usage

rates along the Western corridor.

Only about 2.9 Bcf per day of capacity enters the Southwest

Region. Much of this capacity is on pipeline systems whose

flows are directed toward interconnections with other

interstate systems for transshipment to markets outside the

Southwest Region. The remainder represents flows to local

regional markets that are close to the borders of the region,
5,351

Western

Region

Mexico

5,351

AZ

UT CO

4,250

3,266

350

250

1,270

844

276

2,795 1,824

5,838

844

8,609

KS 564

5,926 2,160

350

5,272

Central

Region

650

47

2,114

MO

2,814

706

MS

7,716

384 13,821

17,636

TN

30

380

25

Southeast

Region

20,846

405

Texas

Oklahoma Arkansas

Louisiana

New Mexico

Leaving: 35,650 

Entering: 2,869 (excludes Gulf of Mexico) 

Estimated Total Throughput Capacity

Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 71

Figure 18. Interstate Natural Gas Capacity Summary for the Southwest Region, 1996

(Volumes in Million Cubic Feet per Day)

Principal Interstate Natural Gas Pipeline Companies Operating in the Southwest Region

Regional Service Level Systemwide Utilization Rates %1

Principal Market Region / Supply System Peak-day Delivery Intercon- 12-Month Peak Summer

Pipeline Name Source(s) Configuration Deliveries Points nects Average Day Offpeak

Regional Secondary System of of

Primary/ Percent of Number Number

2 3 45 6

Regional Pipelines

Koch Gateway Pipeline Co SW Trunk/Grid 75 907 13 57 100 59

Noram Gas Transmission Co SW Trunk/Grid 99 751 32 56 86 61

Mid-Louisiana Gas Co SW Trunk 100 7 3 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 Service

ANR Pipeline Co SW Trunk/Grid 17 21 22 70 100 66

Colorado Interstate Gas Co SW, CE Trunk/Grid 5 11 7 82 104 76

Columbia Gulf Transmission Co SW Trunk 2 10 11 98 101 96

El Paso Natural Gas Co SW Trunk 3 288 6 71 78 73

Florida Gas Transmission Co SW Trunk 8 25 1 71 102 66

Mississippi River Transmission Co SW Trunk 41 32 8 85 92 59

Natural Gas Pipeline of America SW, CE Trunk 7 83 25 84 96 80

Northern Natural Gas Co SW Trunk/Grid 4 45 8 92 107 80

Panhandle Eastern Transmission Co SW Trunk 1 9 0 78 98 58

Southern Natural Gas Co SW Grid/Trunk 2 18 10 66 100 88

Tennessee Gas Pipeline Co SW, Canada Trunk 11 141 29 90 111 70

Texas Eastern Transmission Corp SW Trunk 7 12 29 84 109 49

Texas Gas Transmission Corp SW Trunk 17 58 21 79 111 58

Transcontinental Gas Pipeline Co SW Trunk 1 5 4 83 99 81

Trunkline Gas Co SW, CE Trunk 1 30 16 74 90 66

Transwestern Gas Pipeline Co SW, CE Trunk 67 34 8 60 62 61

Williams Natural Gas Co SW, CE Grid/Trunk 4 86 1 75 82 42
Energy Information Administration 

72 Deliverability on the Interstate Natural Gas Pipeline System

Usage rates are based upon capacity and transportation volumes for the whole system and do not represent regional service only. 1

"Trunk” systems are long-distance trunklines that generally tie supply areas to market areas. “Grid” systems are usually a network of many interconnections and 2

delivery points that operate in and serve major market areas. Some systems are a combination of the two.

Represents the percent of total pipeline system volume delivered within the region on the system peak-day occurring in the 1996-97 heating year. 3

Represents total system capacity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 4

Represents total system capacity divided by the single peak-day volumes delivered in the 1996-97 heating year as reported in FERC Form 2. 5

Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based 6

on FERC Form 11 gas delivery data for 1995) divided by 153 days. April and October are considered to be months that “shoulder” the heating season of NovemberMarch.

NA = Not available.

Sources: Capacity: Federal Energy Regulatory Commission, FERC 567 Capacity Report, “System Flow Diagram” and Annual Capacity Report (18 CFR §284.12);

Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity, as of December 1997. 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, Associated Natural Gas Company’s 30 MMcf gathering and intermediate storage operations within the

per day from Missouri into Arkansas. region performed in conjunction with production—features

About 45 percent (1.3 Bcf per day) of the total entering trunkline usage rates often are more a reflection of the

capacity represents pipeline capacity from Colorado (Central downstream demands of other regional markets rather than of

Region) to New Mexico on three pipelines (Appendix A, demands within the Southwest. 

Table A5). Part of this capacity (about 60 percent) is

redirected toward traditional Western Region markets, The regional interstate pipeline companies, that is, those with

although in recent years a greater portion of this capacity is the majority of their deliveries within the region, together

being directed to interstate interconnections and market account for about one-quarter of the regional deliveries. Most

centers that serve the Midwest marketplace. The average daily of the regional consumption is supplied by local intrastate

utilization rates on these three pipelines ranged from 55 to pipeline companies for which data are unavailable. As the

88 percent in 1996, the lowest being on the Transwestern largest consuming region in the United States, the Southwest

Pipeline system, which was affected by unusual maintenance has many large intrastate pipeline companies and LDCs

needs and construction during off-peak periods. supplying natural gas to consumers. For example, Lone Star

Deliverability Within the Region

Several of the 22 or more interstate pipeline companies

operating within the Southwest Region primarily serve

customers in the region (Figure 18). Three of the larger ones,

Noram Gas Transmission Company, Ozark Gas Transmission

Company, and Valero Interstate Pipeline Company, have

commitments within the region of close to 100 percent of

their total transportation service levels. In addition, several of

the major trunklines exiting the region also maintain sizeable

deliverability levels within the region itself. For instance, in Underground natural gas storage plays a vital role in the

1995, El Paso Natural Gas, Koch Gateway Pipeline, and efficient export and transmission of natural gas from the

Transwestern Pipeline companies delivered 54, 63, and Southwest to other regions, as well as in supplementing

53 percent, respectively, of total throughput to points within regional needs. These underground storage facilities represent

the region on their system peak day. Several of the other over 982 Bcf of working gas capacity (Table 10) and an 84

major exporting pipeline system delivered 25 to 30 percent of estimated daily deliverability level of over 20.5 million cubic

their peak-day volumes within the region. feet. A large portion of this storage is near production fields

In 1996, the average daily utilization rates on the interstate ket demand.

pipelines within the region ranged from 42 to 98 percent.

In general, the average rate within the region was higher in About 38 percent of the region’s daily deliverability from

1996 than in 1990, 57 versus 49 percent. This rate is lower storage is owned by interstate pipeline companies, 29 percent

than the 66-percent average utilization for lines exiting the by independent operators, and 33 percent by LDCs or

region (Appendix A, Table A5), but reflects some of the intrastate pipeline companies. All of the interstate pipelinethat affect trunkline operations to a lesser degree. Also,

Gas Company is the eighth largest LDC in the United States

(in terms of total deliveries), with more than 1.2 million

customers in Texas. The only States in which LDCs are

among the largest customers of the interstate pipeline

companies are Louisiana, where Koch Gateway Pipeline

Company supplies New Orleans Public Service Inc., and New

Mexico, where El Paso Natural Gas Company supplies three

LDCs.

Storage Deliverability

and is used to balance production flows and fluctuating marowned storage, and most of the independently owned, is open

access, that is, working gas storage capacity can be available

to shipper/customers on a first-come, first-served basis

at nondiscriminatory rates. This means that only a limited

amount of the pipeline storage is for system or pipeline use

Energy Information Administration, EIAGIS-NG Geographic 84

Information System, Natural Gas Pipeline Deliverability Database, as of

December 1995. 
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 73

(for load-balancing operations). Most shippers are now attributed to an annual growth rate of only 1.9 percent in

responsible for making their own arrangements with storage residential consumption and 3.2 percent in the industrial

operators to ensure that they comply with the receipt/delivery sector (Table 12).

balancing requirements of the system on which they are

shipping. Although electric utility use of natural gas showed a slight

As a result, a growing amount of regional storage is also gas-fired generating capability increased at a 1.4 percent rate.

linked to the many natural gas market centers in the region Gas-fired generating capacity grew to 57 percent of total

that have become operational during the past 5 years. These electric generating capacity in the region by 1996, the highest 85

centers, often themselves owners of independent storage, rate among regions. Louisiana had the highest percentage,

assist shippers in making short-term arrangements to store 71 percent, with Texas second at 61 percent. Total

excess load or to borrow gas when receipt volumes do not electricity generating capacity in the region increased by only

match delivery requirements or vice-versa, a situation that can 2 percent from 1990 through 1996, at about the same level as

result in imbalance penalties being levied by the transporting installed gas-fired units (Table 13). On the other hand,

pipeline. nonutility generating capability, although accounting for only

The overall peak-day withdrawal capability from storage into 1996, grew by 14 percent during the same period.

the interstate system is approximately 13.7 Bcf per day

(Table 10), the equivalent of about 39 percent of the total In 1990, natural gas provided 40 percent of the total energy

capacity exiting the region. In Louisiana, almost all of the un- input to electric utilities in the region. By 1996, this

derground storage service is available to the interstate system, proportion had fallen to 36 percent. In addition, the total

whereas in Oklahoma, 56 percent is operated as part of the volume of gas consumed within the region by electric utilities

interstate system (Appendix C, Table C1). Industrial and declined by 7 percent during the same period. In spite of this 86

electric utility customers in the region, with variable load regional decline, natural gas use by electric utilities in Texas

demands and high swing requirements, are major users of increased slightly and in 1996 still accounted for 40 percent

high-deliverability, salt cavern storage, most of which is of all gas purchases by utilities in the Nation.

operated by interstate pipeline companies or independents.

Only about a third of the region's storage capacity is owned natural gas is the highest in the Nation. Louisiana, Oklahoma,

by LDCs and used exclusively for local service (Table 10), New Mexico, and then Texas, respectively, use natural gas as

but regional distributors also have access to and use interstate an energy source to a greater degree than any other States in

and independent storage facilities. Most of the LDC-owned the Nation (Appendix C, Table C2). This high level is due to

storage is near major industrial and population centers and has the availability of gas in the region, where the overall ratio of

little impact upon the interstate pipeline network in the area. natural gas production to consumption is 2.25 (Table 11), and

In Texas and Oklahoma, approximately 40 percent of the use of natural gas by industries and electric utilities in the

underground storage capacity is at facilities operated by LDCs region is still the highest compared with use in the rest of the

or intrastate pipeline companies, whereas in Arkansas all of Nation (Table 12).

the storage capacity is controlled by local operators

(Appendix C, Table C1). The industrial sector dominates the regional market,

End-Use Consumption

The Southwest is the only regional marketplace where natural

gas use grew at a slower rate than total energy demand

(Table 11). Since 1990, natural gas consumption in the region

grew at an annual rate of 0.2 percent, while total energy grew

at a 1.3 percent rate. In fact, the use of natural gas as a

percentage of total energy consumed dropped from 40 percent

in 1990 to 39 percent in 1995. Part of this drop can be

annual decrease (0.1 percent) during the period (Table 12),

87

about 1 percent of electric power generated in the region in

88

89

Despite a slight loss in energy share, regional consumption of

consuming 53 percent of the natural gas delivered within the

Southwest Region. The industrial share of natural gas

consumption is highest in Louisiana (63 percent) because of

its large petrochemical industry. From 1990 to 1996,

industrial customers in all States in the region increased

average natural gas use at an annual rate of 11 percent, with

New Mexico (where industrial sector represents the smallest

See, Energy Information Administration, Natural Gas 1996: Issues and primarily because of high gas prices that developed in the early part of the 85

Trends, DOE/EIA-0560(96) (Washington, DC, December 1996),Table 8, decade.

Chapter 3. Energy Information Administration, Natural Gas Annual 1996,

Includes supply to the interstate system. DOE/EIA-0131 (Washington, DC, September 1997) and previous editions. 86

Derived from: Energy Information Administration, Form EIA-860, 87

“Annual Electric Generator Report” (1990-1996).

During the 1980s, the proportion of natural gas consumed by electric 88

utilities in the region dropped from 66 percent in 1980 to 41 percent in 1989

89
Energy Information Administration 

74 Deliverability on the Interstate Natural Gas Pipeline System

market share) and Texas showing the largest increases California have mandated reductions in consumption of

(Appendix C, Table C4). While natural gas lost in terms of residual fuel oil as a boiler fuel, resulting in increased 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 percentage points between 1990 Act Amendments of 1990, the South Coast Air Quality

and 1996 (Table 12). Management District issued rules that prohibit price-induced

The residential and commercial 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

percent of natural gas consumption in the region, virtually the use of fuel oil at all their power plants in order to reduce

unchanged 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 projected preference for gas because of environmental

per residential customer. Since 1990, the number of concerns was a primary force behind the 42-percent increase 90

residential and commercial gas customers increased in pipeline capacity into the Western Region between 1990

somewhat, 1.2 and 2.2 percent per year, respectively, but not and 1996. However, the expected growth in the natural gas

enough to affect their respective markets (Table 13). market did not materialize as an economic slowdown resulted

Recent and Proposed Expansions

The principal arena for pipeline capacity expansions in the

Southwest Region during the next several years will be in the

intrastate market, mostly to expand access to new production

areas and improve deliverability to local markets and links

with the interstate system. In particular, producers in southern

Texas and the Cotton Valley Trend area of eastern Texas will

be seeking greater access to the interstate transmission

network. In the interstate market, the primary effort will be to

forge greater access to deep water developments in the Gulf

of Mexico and to improve service at the several market

centers in the region.

In 1997, 10 expansion projects were completed within the Eight interstate pipeline companies provide service to and

region, adding more than 3.7 Bcf to regional pipeline within the Western Region, the fewest number serving any

capacity. Six of these projects were designed to bring region (Figure 19). Capacity entering the region is also the

additional supplies onshore from the Gulf of Mexico: three lowest of all gas-importing regions, approximately 10.1 Bcf

major gathering systems (1.1 Bcf per day) and three pipelines per day. Slightly more than half of this capacity is on pipeline

(2.1 Bcf per day) coming onshore to Louisiana (Appendix B). systems that carry gas from the Rocky Mountains area and the

The remaining projects were designed principally to expand Permian and San Juan Basins (Appendix A, Figure A5).

interstate access to production in West Texas and New These systems enter the region at the New Mexico-Arizona

Mexico. Fourteen additional projects are scheduled for and Nevada-Utah State lines. The rest arrive on pipeline

completion in 1998 and two in 1999, which would add systems that access Canadian supplies at the British

3.7 Bcf to regional capacity. Currently, no projects have been Columbia-Idaho and Washington State border crossings.

announced that would go beyond 1999.

Western Regional Market

The Western Region has some of the strongest environmental

initiatives in the Nation, many of which call specifically for

greater use of natural gas. For instance, regulatory agencies in

burning of fuel in dual-fired utility boilers. The Southern

in underutilization of this new capacity.

California dominates the regional natural gas market because

of its large population, the highest in the Nation, and because

of its relatively high gas use. California customers account for

about 59 percent of the energy consumed in the region and

74 percent of the natural gas use (Appendix C, Table C2).

One utility, Pacific Gas and Electric, distributed almost

5 percent of the natural gas delivered to end-use customers in

the United States in 1996. Another, Southern California Gas

Company, is the largest gas distributor in the United States

and perhaps in the world.

Entering/Exiting Capacity

Capacity into the Western Region increased overall by

42 percent, or 3.0 Bcf per day, between 1990 and 1996

(Table 9). The majority of this increase occurred on routes

transporting gas from Canada, where 48 percent more

capacity was implemented. PG&E Transmission-Northwest

(formerly Pacific Gas Transmission Company) and Northwest

Pipeline Company accounted for all of these capacity

additions. In spite of a general economic downturn in the

region during the early 1990s, particularly in California,

average capacity usage rates on these routes recovered in

See, Energy Information Administration, Natural Gas Annual 1996, and 90

previous editions.
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 75

1996 (after falling between 1993 and 1995) to reach or exceed

their 1990 average rates.

Three new interstate natural gas pipeline systems were placed

in service between 1991 and 1995 in the region and four

existing systems underwent major expansions. While they

were being built, however, the regional marketplace,

especially in California, saw an overall decrease in economic

activity and a slowdown in the growth of natural gas demand.

A casualty of the slowdown has been the repeated

postponement of the Altamont Pipeline project (737 MMcf

per day), which was slated to serve the California market with

gas transported from western Canada. Currently, the project 91

is being marketed as a potential route for transporting

Canadian supplies eastward via the expanding Trailblazer

system (which 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. 
Canada

1,126

3,786

2,982 122

2,063

941 481

780

95

60

45

Mexico

191

MT

2,660

2,632

158

254

298

750

444

5,118

WY

UT

NM

5,331

Central

Region

1,194

Southwest

Region

5,351

California

Arizona

Nevada

Washington

Oregon

Idaho

Leaving: 343 

Estimated Total Throughput Capacity

Entering: 10,674 (excludes offshore) 

298

Energy Information Administration 

76 Deliverability on the Interstate Natural Gas Pipeline System

Figure 19. Interstate Natural Gas Capacity Summary for the Western Region, 1996

(Volumes in Million Cubic Feet per Day)

Principal Interstate Natural Gas Pipeline Companies Operating in the Western Region

Regional Service Level Systemwide Utilization Rates %1

Principal Market Region / Supply System Peak-day Delivery Intercon- 12-Month Peak Summer

Pipeline Name Source(s) Configuration Deliveries Points nects Average Day Offpeak

Regional Secondary System of of

Primary/ Percent of Number Number

2 3 45 6

Regional Pipelines

El Paso Natural Gas Co. SW None 76 330 2 71 78 73

Kern River Transmission Co CE Trunk 99 30 0 98 109 96

Mojave Pipeline Co SW Trunk 100 17 2 97 119 95

Northwest Pipeline Co Canada Trunk/Grid 64 282 1 90 94 54

Pacific Gas Transmission Co Canada Trunk 109 190 3 86 96 85

TransColorado Pipeline Co CE Trunk 100 NA NA NA NA NA

Transwestern Gas Pipeline Co SW Trunk 31 6 1 60 62 61

Tuscarora Gas Transmission Co Canada Trunk 109 4 1 NA NA NA

Usage rates are based upon capacity and transportation volumes for the whole system and do not represent regional service only. 1

"Trunk” systems are long-distance trunklines that generally tie supply areas to market areas. “Grid” systems are usually a network of many interconnections and 2

delivery points that operate in and serve major market areas. Some systems are a combination of the two.

Represents the percent of total pipeline system volume delivered within the region on the system peak-day occurring in the 1996-97 heating year. 3

Represents total system capacity divided by the total annual volumes (divided by 366 days) delivered in 1996 as reported in FERC Form 2. 4

Represents total system capacity divided by the single peak-day volumes delivered in the 1996-97 heating year as reported in FERC Form 2. 5

Represents a summer (nonheating season) usage level, using the sum of volumes delivered during the nonshoulder months of May through September (based 6

on FERC Form 11 gas delivery data for 1995) divided by 153 days. April and October are considered to be months that “shoulder” the heating season of NovemberMarch.

NA = Not available.

Sources: Capacity: Federal Energy Regulatory Commission, FERC 567 Capacity Report, “System Flow Diagram” and Annual Capacity Report (18 CFR §284.12);

Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity, as of December 1997. 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.”
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 77

The new pipeline systems constructed during the period Arizona two, and California five. In addition, a company such

include: (1) the Kern River Pipeline (750 MMcf per day) as Washington Water Power operates in more than one State,

from Opal, Wyoming, to Kern County, California, currently providing service in Oregon, Washington, and California.

operating at about 100 percent utilization during peak periods

and 93 percent during baseload periods; (2) Mojave Pipeline Until the early 1990s no interstate pipeline companies

(450 MMcf per day) from the Arizona/California border to operated within California; all supplies were received from

Kern County, merging with the Kern River system, currently the interstate companies at the State border. That changed

operating at about full capacity during peak periods but as with the completion of the Kern River and Mojave Pipeline

low as 40 percent during other periods; and (3) Tuscarora system into southern California in 1993 and the Tuscarora

Pipeline (110 MMcf per day) from the northern California Pipeline system into northern California in 1995. However,

Border to Reno, Nevada, which began operations in 1995 even today, most service within California is provided by

(load factors are unavailable). Pacific Gas and Electric Company and Southern California

PG&E Transmission-Northwest had the largest expansion companies play dual roles as LDCs for their core customers

during the period, adding more than 870 MMcf per day to its and open-access transporters for major shippers, such as

system from the Canada/Idaho border to the northern industrial users and electric utilities, within their respective

California border, a 55-percent increase. While the system service territories. They also serve as intrastate pipelines with

currently operates at about 90 to 95 percent capacity during interconnections to the other LDCs serving the State.

peak periods (compared with 100 percent in 1990), the range Southern California Gas Company provides distribution serbetween high and low is only about 8 percentage points. vice in southern California. Pacific Gas and Electric claims

Northwest Pipeline Company (NWPL), which also brings northern California as its service territory but also serves as a

Canadian supplies into the region, increased its capacity by vehicle to move some Canadian gas supplies to southern

more than 240 MMcf per day, adding greater bidirectional California.

flexibility and redirecting some of its flows to growing

markets within its operational territory. NWPL’s overall All of the pipelines entering the region, with the exception of

utilization level is higher than it was in 1990. The system Northwest Pipeline Company, terminate there as well. Each

operates at about full capacity during peak periods, although also has major commitments in the region. For instance, of the

rates fell as low as 54 percent during off-peak periods. 645 delivery and interconnection points on the El Paso

Expansions of the El Paso Natural Gas Company and 76 percent of the peak-day volumes delivered off its system

Transwestern Pipeline Company systems during 1992 in 1995 (Figure 19). All of Pacific Gas Transmission’s

and 1993 provided greater access to San Juan Basin 192 delivery points are within the region, with the system

production. The El Paso system experienced an increase of transporting 2.7 Bcf on its peak day in 1996 (Table 1). 

371 MMcf per day, or 17 percent, while Transwestern’s

system increased by 680 MMcf per day. The interstate pipeline companies within the region operated 92

Deliverability Within the Region

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 produces

any substantial quantity, about 15 percent of its annual

consumption level (Appendix C, Table C2). Another

important characteristic of the region is that local gas

distribution services are dominated by a few large companies.

Other than some small municipal gas distributors, Idaho,

Washington, and Nevada have only three LDCs, Oregon and Most of the underground storage facilities in the Western

Gas Company, the two largest LDCs in the Nation. The two

Natural Gas system, 341 are within the region and represented

at an average utilization rate of about 66 percent in 1996.93

That was down from an 84-percent level in 1990. The

difference reflects, to a large degree, the drop in capacity

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

capacity utilization.

Storage Deliverability

Region, especially in California which has 91 percent of the

region’s working gas capacity, are used as market area supply

reservoirs to store Canadian gas supplies, which flow and are Transwestern completed its San Juan expansion project in 1996 and 92

increased capacity further in the area in 1997. Its completion expanded

capacity on the New Mexico side of the basin, thus relieving a production

constraint situation that has hindered the flow of production out of the area for

several years. The Transwestern system expansion prior to 1996 coincided Energy Information Administration, EIAGIS-NG Geographic

with the construction of the Mojave Pipeline system, the two interconnecting Information System, Natural Gas Pipeline State Border Capacity Database, as

at the Arizona/California border. of December 1997.

93
Energy Information Administration 

78 Deliverability on the Interstate Natural Gas Pipeline System

received at a rather constant rate (Appendix C, Table C1). The (38 percent in 1996), particularly because of the enhanced oil

California storage fields are more like production (area) recovery (EOR) industry in southern California. The EOR

storage located at the market end of the supply corridor. The market, which uses natural gas to generate steam for injection

availability of this storage is one of the reasons why the onto heavy-oil fields, accounts for about 200 Bcf of the

pipelines entering the region operate at such 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 percent annual

operators to address the varying needs of their local customers growth in the industrial sector in California since 1993, when

and shippers while maintaining a steady flow on their the Kern River and Mojave pipelines first entered this market.

systems. Another factor in the growth in the industrial sector is the

All the underground storage sites in the region are State. Natural gas accounted for more than 57 percent of the

conventional reservoir storage, owned and operated by LDCs power generated from these facilities in 1996 and constituted

(Table 10). Most of the storage is owned by the two largest about 12 percent of all electric power generated in the State.

California intrastate systems, PG&E and SoCal Gas. The rest

is located in Washington State and Oregon and is used for Residential customers have a 26-percent share of the

seasonal storage and as peaking facilities. California natural gas market, electric utilities 18 percent, and

Despite the region’s relatively temperate climate, LNG Table C3). Hydropower electric generation is the major

storage is also used by LDCs in the market, especially in the competitor of natural gas in the State. In past years, for

northern States of Washington and Oregon (Appendix C, instance, when severe drought conditions developed that

Table C1). LNG as a peaking fuel is very compatible restricted hydro-power generation, natural gas saw a major

with the need for occasional supplemental supply support, gain in its use for electric generation. As water levels

especially because the geologic makeup of the region improved, however, natural gas lost its market advantage and,

precludes much further development of underground storage as a result, the use of natural gas for this purpose dropped by

facilities. Installation of LNG facilities under these conditions 7.4 percent per year in the State from 1990 through 1996.

also lessens the need for additional and expensive pipeline

capacity when incremental supplies are needed only for the Nonetheless, the electric utility industry remains a significant

short term. user of natural gas. In three of the six States in the region

End-Use Consumption

Natural gas consumption in the Western Region increased at

an average annual rate of about 4 percent between 1990 and

1996, whereas overall energy output increased at only a

0.3 percent rate (Table 11). The slowdown in the regional

economy during the early 1990s was the main factor in the

decreased energy growth. The higher growth in natural gas

consumption can be attributed to its use as a substitute for

hydropower when water levels were low and to its increased

use for enhanced-oil-recovery operations in California.

Environmental dictates also brought about increased

substitution of natural gas for less clean-burning fuels.94

Consumption by California customers accounts for 59 percent

of the energy consumed in the region and 74 percent of the

natural gas. In 1995, 26 percent of the total energy consumed

in California was natural gas (Appendix C, Table C2). The

industrial sector dominates the California gas market

large number of cogeneration sites (more than 450) in the

commercial customers only 13 percent (Appendix C,

(Arizona, Nevada, and California), the electric utility industry

accounts for 16 to 38 percent of total natural gas deliveries to

consumers (Appendix C, Table C3). From 1990 through

1996, gas-fired electric generation capacity in the region grew

at an annual rate of only 0.3 percent, 5.6 percent in Oregon

and 3 percent in Nevada.

In the northern States of the region—Idaho, Oregon, and

Washington—the industrial segment is the predominant user

of natural gas, accounting for more than 48 percent of the

natural gas market in each State. Average annual industrial

consumption of gas in these States increased by about

6.9 percent between 1990 and 1996, while the commercial

and electric utility sectors saw a decrease in natural gas

market share. These three States also showed some of the

largest gains in overall energy consumption throughout the

period. The low usage of natural gas in these States for

electricity generation is primarily because of their extensive

hydroelectric capacity.

Recent and Proposed Expansions

In 1997, two projects were completed in the region—a 25-

MMcf-per-day export crossing with Mexico and a 12-MMcfper-day pipeline expansion from Nevada to California. No

new capacity has been built into the region since 1993.

Coincidently, Federal and State environmental regulations are 94

encouraging more natural gas use, particularly in applications where petroleum

products and coal dominate the market. In some parts of the region,

regulations to limit atmospheric emissions may make natural gas the only

fossil fuel that can be used for electric power and steam generation.
Energy Information Administration 

Deliverability on the Interstate Natural Gas Pipeline System 79

However, the growing economies of the northern States in the If all the projects currently proposed were built—and that is

region—Idaho, Oregon, and Washington—may increase highly unlikely since several have targeted the same

capacity needs. The two major interstate pipeline companies markets—interregional capacity would increase by as much

serving these States, Pacific Gas Transmission and Northwest as 14.7 Bcf per day, or about 17 percent, from the 1996 level.

Pipeline, have announced plans to add additional Additional projects that are limited to providing service

deliverability during the next several years, although the final within a specific region comprise another 15.3 Bcf per day of

levels have yet to be determined. capacity.

Outlook

It appears that most, if not all, natural gas consumer markets

in the United States have adequate service to meet their

unique needs. Interstate pipeline capacity into each of the six

regional markets has increased since 1990 at a pace consistent

with the growth in demand. Furthermore, proposals for

expanding the network are in line with current projections for

regional natural gas demand growth during the next several

years.95

Open-season exercises conducted by the initiators of the

current inventory of expansion proposals have resulted in bids

for future capacity sometimes in excess of what had been

initially offered as a project expansion estimate. This would

seem to indicate that bidders/planners within local markets

also believe that demand will grow substantially during the

next several years. Planners at the local level usually possess

better knowledge of the customer profiles within their own

areas and, therefore, their bids for future pipeline capacity can

be viewed as relatively firm support for the expansions. 

In some cases, however, these bids for capacity are being

made by marketers and other parties who are not that

intimately involved in the local market but want to ensure

their access to new capacity in the future. This new capacity

would provide them with alternative routes to meet their

customers’ desires for access to least cost supplies rather than

to address demand growth.

Underground storage operations, which facilitate both market

center services and efficient pipeline operations, will also be

expanding significantly over the next several years, many in

support of market center or pipeline expansion. For instance, 96

the implementation of the proposed Vector pipeline, from

Chicago to Dawn, Ontario, via the U.S. Midwest, will require

the expansion of several storage facilities in Ontario and in

Michigan to serve its shippers. Likewise, in the southern

States of Texas, Louisiana, and Mississippi, where a number

of market centers are located, including the Henry Hub, a

number of high-deliverability salt cavern storage facilities are

being built or expanded to handle growing production out of

the Gulf of Mexico and increasing business between regional

hubs such as those located in the Midwest (Chicago) and the

Northeast (Pennsylvania and New York). In these States

alone, proposed (through 2001) increases in daily

deliverability from storage sites that directly or indirectly

support market or trading centers amount to 2.2 Bcf per day,

or 5 percent more than current levels.

The services and flexibility offered at natural gas market

centers can be expected to be expanded and improved. The

Chicago market center, for example, should grow as Canadian

import and Southwest supplies (via the Henry Hub) expand

into the area and much of this gas is redirected to the

Northeast Region. The Leidy hub in Pennsylvania is the

transaction and transfer point for several market centers

serving the Northeast and can be expected to become key to

moving gas from the Midwest to New England markets and

other parts of the Northeast.

Nevertheless, close scrutiny and detailed economic analyses by 95

regulatory authorities will result in some projects being deemed unnecessary

and thus not approved. The analyses are done in an effort to avoid, as much Energy Information Administration, “U.S. Underground Storage of

as possible, the burden of costs to future ratepayers that are associated with Natural Gas in 1997: Existing and Proposed,” Natural Gas Monthly,

underutilized or uncompleted projects. DOE/EIA-0130(97/09) (Washington, DC, September 1997).

96
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 79

5. Access to Transportation Markets

The physical capability of the U.S. natural gas pipeline This chapter provides a general picture 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 contractual structure governing the flow of capability of the system, on the basis of data for a sample of

gas along the network and the shipper’s access to pipeline 46 interstate pipeline companies that accounted for 97 percent

capacity. Under Federal Energy Regulatory Commission of interstate transportation deliveries in 1996. The chapter

(FERC) Order 636, which was implemented in November examines how shippers reserve interstate pipeline capacity in

1993, market participants must make their own arrangements today’s marketplace and identifies how much capacity is

for shipping gas. The contract serves as the service agreement controlled by primary shippers holding firm contracts. It also

for the level, quality, location (e.g., receipt and delivery calculates capacity release levels to identify the portion of

points), and price for the transportation service. reserved capacity that may be accessed on the release market.

Shippers can contract for several types of transportation indicate utilization, the volume of gas transported under firm

services, including high-quality firm services, such as firm and interruptible services is also studied to complete the

transportation and no-notice service, and those services picture of transportation market accessibility. 97

subject to disruption, such as interruptible transportation and

released capacity subject to recall. The types of services Other parts of the interstate natural gas delivery system can 98

selected depend on the purpose for which the gas is being also influence the level of a customer’s reliance on the

moved. For example, a local distribution company responsible transportation market, such as the type and availability of

for supplying the gas needs of residential and commercial storage and hub services. While these services may

customers is likely to have a greater share of its transportation supplement transportation services, they cannot fully

under firm contracts than an industrial shipper that can use substitute for supply-to-market transportation of natural gas.

interruptible service or easily switch to an alternative fuel. Therefore, the focus of this chapter is on the services used for

The value of a particular type of transportation service to a trading are measured on a heat content or Btu basis to be

shipper will depend on where and when it is available, its consistent with the units generally used in natural gas

cost, and how it fits into the shipper’s overall portfolio of contracts.

services. If a shipper needs to have natural gas delivered to a

particular point next week, it would contract for service along

a line that has the capacity and services available to make that

delivery. Similar services along a pipeline segment in another

area or for a different time period would not have the same

value to the shipper. The availability of each type of

transportation service depends on the physical capability of

the pipeline network, how much of that capacity is reserved

by shippers, the terms and types of the contracts in place, and

the extent to which current contract holders use the system.99

All of these factors must be considered when assessing the

overall deliverability of the pipeline transportation system.

Since the ownership of system capability does not necessarily

long-haul transportation. In the chapter, capacity and capacity

Estimating Capacity Availability

A question that is often raised is how much of the existing

pipeline transmission capacity is available to meet additional

firm service demand. In this analysis, the estimated available

capacity (unused firm service capability) of the current system

to transport natural gas is considered the sum of the amounts

of unreserved capacity, unused released capacity, and unused

firm contracted capacity. The total capability of the system

can be divided between the reserved or committed capacity

and the unsubscribed capacity. A subset of the reserved

capacity can be identified as capacity released to other

shippers. Although a significant amount of pipeline capacity

is used throughout the year, some remains unused. The

relationship between capability and utilization is illustrated in

Figure 20. This particular example is not derived from actual

information and may not resemble the scale of services,

capacity, and utilization on any specific pipeline system.

However, the chapter uses the concepts displayed in Figure 20

to analyze shippers’ ability to access transportation services

on a regional and systemwide basis.

No-notice service is generally a combination of firm transportation and 97

storage services used to re-create the quality of service that customers

previously received through pipeline company sales service (see Glossary). It

allows shippers to use their full capacity commitment without advanced

scheduling.

About 40 and 35 percent of the released capacity during the 1996 98

nonheating season and 1996-97 heating season, respectively, were not subject

to recall and thus may be considered high-quality firm service.

If current capacity holders do not nominate to the pipeline to use their 99

capacity (see p. 81), the pipeline company may offer the unused capacity to

other shippers. 
Firm Contracted

Capacity

Released

Capacity

Unsubscribed

Capacity

Total

Capability

Uncommitted and Unused

by Firm Shippers

Released but Unused

by Firm Shippers

Committed but Unused

by Firm Shippers

Estimated

Available Capacity

Utilized

Capacity

Utilization

Released Capacity

Used by Firm Shippers

Firm Contracted Capacity

Used by Firm Shippers

Capacity

Energy Information Administration

80 Deliverability on the Interstate Natural Gas Pipeline System

Figure 20. Relationship of Capacity and Utilization

Note: A firm shipper is one using firm transportation services.

Source: Energy Information Administration, Office of Oil and Gas.

The maximum capability of the pipeline system is used in this uniform data on peak-day and monthly transportation were

analysis as the basis against which all other variables are available for each company. The estimated maximum

measured to determine accessibility. The analysis uses a capacity of each company was determined by choosing the

slightly different approach to determine maximum capability largest reported amount from the group of four sources of

than that of Chapter 3, which estimates pipeline capacity on capacity information used in this analysis (see

the basis of design throughput capability at State border “Transportation System Access,” Appendix D). A pipeline

crossings. This chapter considers maximum capability to be company was considered to be located in the region in which 100

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 can be met at the The sample pipeline companies have a total maximum

delivery point, then the transportation system can move that capability of 127 trillion Btu per day (Table 14). Thus,

volume of gas. theoretically, they could deliver more than 46 quadrillion Btu 101

In the analysis, the maximum transportation capability of the by major interstate pipeline companies in 1996. While this

interstate pipeline system is estimated on the basis of capacity figure may provide a relatively good estimate for maximum

data for a sample of 46 major pipeline companies that capability, the extent to which shippers reserve and use this

accounted for 97 percent of interstate transportation deliveries capacity provides a better indication of its availability.

in 1996. The sample was selected to ensure that adequate and

102

of gas annually, or almost 1.6 times the total gas transported

Chapter 3 discusses the capability of pipeline systems to move gas from transportation capability and use, including: annual capacity reports and 100

production to market areas. Therefore, system capability is estimated by accompanying Format 567, “System Flow Diagrams,” filed annually with the

measuring the amount of natural gas that can flow across State borders in a Federal Energy Regulatory Commission (FERC) by major interstate pipeline

given day to determine the utilization of interregional transportation. It companies under 18 CFR §284.12 and §260.8; FERC Index of Customers

includes data only for those pipeline segments that reported gas flow. filing; FERC Form 2, “Annual Report of Major Natural Gas Companies”;

It should be noted that most pipeline companies’ systems handle loads FERC Form 11, “Natural Gas Pipeline Company Quarterly Statement of 101

through a series of receipt and delivery points and that all gas received by the Monthly Data”; and Energy Information Administration, Office of Oil and

pipeline does not enter at a single point. Nor does a pipeline company deliver Gas, Capacity Release Awards dataset. See Appendix D for more detailed

all its customers’ maximum demands on the same day. information on data sources.

Several sources of information are used to develop a picture of 102
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 81

Table 14. Reserved Firm Transportation Capacity by Region, July 1996 and January 1997

Firm Transportation Contracts

As of July 1, 1996 As of January 1, 1997

Region (trillion Btu per day) (trillion Btu per day) (percent) (trillion Btu per day) (percent)

Maximum Capability Capacity Ratio Capacity Ratio

Concentration Concentration

Central 16.6 13.7 82 16.0 96

Midwest 31.1 24.2 78 28.4 91

Northeast 44.2 33.4 76 37.1 84

Southeast 6.0 5.1 85 4.9 81

Southwest 12.6 5.9 47 6.2 49

Western 16.6 14.3 86 14.0 84

U.S. Total 127.0 96.6 76 106.6 84

Note: Totals may not equal sum of components because of independent rounding.

Sources: Energy Information Administration (EIA), Office of Oil and Gas, derived from pipeline company reports filed with the Federal Energy

Regulatory Commission (FERC): 1996 Peak-Day Capacity Report (18 CFR §284.12); 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 Activity

Shippers must first obtain capacity to effectuate movement of

gas on a pipeline system. Therefore, all shippers must have

access to the firm or interruptible capacity markets to meet

their needs. There are three ways in which a shipper can

obtain pipeline transportation service:

 Contract for firm transportation service. The 103

shipper reserves a specific amount of capacity via a

contract with the pipeline company.

 Contract for interruptible transportation service.

Capacity that is not committed to firm transportation

service or capacity that remains unused by the holder of

firm transportation capacity may be offered by the

pipeline as interruptible service. These contracts are

typically for short periods of time. Changes in market

conditions affect the size and availability of interruptible

service.

 Obtain capacity via the capacity release market. A

shipper with unused capacity for firm transportation

service may choose to trade that capacity on the release

market. The releasing shipper may or may not subject the

capacity to recall, thereby making the service quality

similar to interruptible or firm transportation service.

Once a shipper has a right to use capacity, it nominates, in

writing or electronic form, the daily amount of gas it wants to

be received, delivered, or stored by the pipeline company.

The shipper nominates capacity at specific receipt and

delivery points along the pipeline system. The nomination of

daily volumes may be renewed or changed on a monthly,

daily, or intraday basis and may be for any quantity up to the

maximum daily quantity (MDQ) specified in the contract. 

Next, the pipeline company confirms each shipper’s

nomination and inquires into any needed changes. Because

there are many shippers making nominations, the pipeline

company must look at the aggregate quantities and determine

whether the pipeline system can tolerate the overall level of

nominations during the confirmation process. 

Once the pipeline company ascertains that the system can

handle all shipper nominations, it schedules the gas,

specifying gas flows in and out of each receipt and delivery

point. The pipeline company determines priorities based upon

type of service. For example, firm service will be scheduled

ahead of interruptible service.

During the 1996-97 heating year (the 12 months ended

March 31, 1997), on average 78 percent of physical capacity

was committed to firm transportation contracts, according to

pipeline company information filed with the Federal Energy

Regulatory Commission. Although the amount of reserved

capacity changes over time, particularly as the seasons

change, the share of physical capacity committed to firm

transportation service remained fairly constant during 1996

and 1997. A portion of the firm capacity, approximately

20 percent, was traded during the year to replacement

Includes firm transportation service and no-notice service. 103
Energy Information Administration

82 Deliverability on the Interstate Natural Gas Pipeline System

shippers via the capacity release market. Interruptible 104

service accounted for 16 percent of transportation throughput

during the 1996-97 heating year.105

Activity in primary firm capacity markets, which include 106

firm transportation, no-notice service, and sales service, has 107

generally increased during the years since industry

restructuring under FERC Order 636. Since 1992, the 108

volume of gas transported using firm services has grown at an

average rate of 9 percent per year. Transportation under firm

services increased from 11.5 quadrillion Btu in 1992 to

16 quadrillion Btu in 1996. Since its inception in 1993, the

capacity release market has also grown dramatically.

Although release activity declined slightly in 1996, it still

represented 16 percent of the gas delivered for market at

3.6 quadrillion Btu. Unlike the firm and release markets, the

interruptible transportation market has consistently declined

since 1992. In 1996 only 2.9 quadrillion Btu was moved by

interruptible transportation compared with 8.3 quadrillion Btu

in 1992.

On the surface these results might imply that capacity markets

are getting tighter, thus, squeezing out the nonfirm capacity

market. However, transportation activity under various

services provides only part of the story behind transportation

market accessibility. In addition to throughput levels, the

pipeline system’s level of unsubscribed capacity must also be

considered. For example, a pipeline system may have enough

excess capacity to create a discounted firm transportation

service that competes with interruptible transportation.

Likewise, deliverability on the U.S. pipeline system is as

much a product of availability as it is physical capacity. All

the physical space on a pipeline system may be reserved

under contract (fully subscribed), but if the reserved space is

not in use by the firm shipper, it may be accessed by another

shipper using interruptible or short-term firm service offered

by the pipeline company. The underutilization of the pipeline

system may also promote a strong market for released

capacity. Therefore, all of these components should be

reviewed to characterize the availability and accessibility of

various transportation services.

Firm Transportation Service

As previously discussed, most gas deliveries in 1996 were

under firm transportation contracts. Shippers may elect to

contract for firm transportation service on an annual or

seasonal basis. With a firm transportation contract, the shipper

may reserve, what it estimates to be, the highest demand it

will incur on the pipeline system on any given day.109

Correspondingly, the pipeline company agrees to make that

amount of capacity available to the shipper on a daily basis.

Pipeline companies disclose the amount of capacity reserved

by each firm customer in the quarterly Index of Customers

filing to the FERC. For each firm contract that is effective the

first day of the calendar quarter, pipeline companies are

required to provide: the name of the shipper, the amount of

capacity reserved, the rate schedule under which service is

provided, the beginning and ending dates of the contract, and

whether the contract contains a rollover clause. The Index of

Customers’ filing provides the measurement of the reserved

portion of the pipeline company’s system capacity.

Data from these quarterly filings indicate that a large amount

of pipeline capacity is reserved under firm contracts

(Figure 21). In fact, the reservation concentration ratios—the

percentage of maximum capability that is under a firm service

contract— for the nonheating season (April through October)

range from 76 to 86 percent in five of the six regions. The

exception lies in the Southwest Region, which has a

subscription rate of only 47 percent (Table 14). Subscription

rates increased significantly during the heating season in the

Central (from 82 to 96 percent), Midwest (from 78 to

91 percent), and Northeast (from 76 to 84 percent) regions,

while all other regions experienced little change in reservation

concentration between seasons.

Concentration ratios in the Southwest are lower than in the

other regions because of the abundance of capacity on several

production-oriented pipelines located in the region. Excluding

these pipeline companies from the analysis would increase the

concentration ratios in the Southwest from 47 to 73 percent

for the nonheating season and from 49 to 77 percent for the

heating season. However, removing these companies from the

sample would not significantly alter the national

concentration ratios; the ratios for the nonheating and heating

seasons as well as the heating year would increase by

3 percentage points to 79, 87, and 81 percent, respectively.

Includes capacity subject to recall and that not subject to recall. 104

Based on information compiled by the Energy Information 105

Administration from FERC Form 11, “Natural Gas Pipeline Company

Quarterly Statement of Monthly Data” (1996).

“Primary” refers to firm service obtained directly from the pipeline 106

company.

The volume of gas moved under pipeline company sales service has A few pipeline companies allow customers to elect different amounts of 107

been virtually zero since 1995. service for the heating and non-heating seasons. This enables a heating load

Interstate Natural Gas Association of America (INGAA), Gas customer to subscribe to the required winter capacity without holding 108

Transportation Through 1996 (May 1997). unneeded capacity in the summer.

109
Central Midwest Northeast Southeast Southwest West

0

20

40

60

80

100

Reserved Capacity Unsubscribed Capacity

(Percent)

Regional Capability

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 83

Figure 21. Concentration of Reserved Firm Capacity by Region, April 1996 - April 1997

Note: Includes contracts for no-notice and firm transportation services.

Sources: Energy Information Administration (EIA), Office of Oil and Gas, derived from pipeline company reports filed with the Federal Energy

Regulatory Commission (FERC): 1996 Peak-Day Capacity Report (18 CFR §284.12); 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).

Since shippers base their contracted amounts on pipeline company electronic bulletin board that it has

their maximum demand for any given day, they will available capacity. Interested parties then submit sealed

frequently have unused capacity during the course of a year. bids to the pipeline company, which evaluates the bids and

In addition, the average price of firm capacity tends to be high selects the winning replacement shipper based on selection

because of the cost classification and allocation methods used criteria approved by the releasing shipper. This mechanism

by the Federal Energy Regulatory Commission to determine provides prospective shippers’ access to firm capacity that

maximum transportation rates. Shippers pay to reserve otherwise may not have been available.

capacity whether it is used or not. Primary firm shippers

frequently release their unused capacity to mitigate the high The growth in the capacity release market indicates that

reservation charges. shippers are embracing this capacity trading system. The

Capacity Release Market

The capacity release market, established under FERC Order

636, provides shippers a method to resell unused capacity on

either a prearranged or open bid basis. Release transactions 110

take place when a primary shipper places a notice on the

111

112

amount of capacity held daily by replacement shippers has

grown significantly since the beginning of the capacity release

market (Figure 22). The amount of capacity held by

replacement shippers during the 12-month period ending

March 1997 totaled 7.4 quadrillion Btu, a 22-percent increase

over the previous 12-month period and almost double the

level for the 12 months ending March 1995 (Figure 23).

Releasing shippers have the option of (1) prearranging a release for 1 Internet sites by June 1997. 110

month or less or for any length of time at maximum costs, or (2) posting a A primary shipper may release all or part of its capacity on a long-term

notice of capacity availability on the pipeline company’s electronic bulletin or short-term basis and receive credit from the release to its pipeline company

board for open bidding. account.

FERC Order 587-B (Docket RM 96-1-003) required that pipeline 111

companies begin offering capacity release and other transactions through their

112
Central Midwest Northeast Southeast Southwest West

0

1

2

3

4











































 











Capacity Held (Quadrillion Btu)





12 Months Ended March 31

1996

1997

1995

0

5

10

15

20

25

30

35

Index (November 1, 1993 = 1)

Capacity Held

Active Contracts

NovJan Jan

1993 1995 1994 1996 1997

Jan Jan

Energy Information Administration

84 Deliverability on the Interstate Natural Gas Pipeline System

Figure 22. Growth in the Capacity Release Market, November 1993 - March 1997

Source: Energy Information Administration, Office of Oil and Gas, derived from Federal Energy Regulatory Commission, Electronic Data

Interchange (EDI) data.

Source: Energy Information Administration, Office of Oil and Gas, derived from: November 1993 - July 1994: Pasha Publications, Inc.

July 1994 - March 1997: Federal Energy Regulatory Commission, Electronic Data Interchange (EDI) data.

Figure 23. Capacity Held by Replacement Shippers, by Region and Heating Years, 1994-95 – 1996-97
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 85

The activity in the capacity release market provides a measure The West and Midwest regions also experienced significant

of the reserved capacity that is unused by the primary shipper percentage increases over their 1995-96 levels, although the

and is of value to the replacement shipper. The most capacity amounts are less than those of the Northeast Region.

comprehensive information available on the release market The amount of capacity held by replacement shippers in the

concerns data on capacity that is awarded to replacement West during the 1996-97 heating year increased by almost

shippers. While actual utilization cannot be accurately 50 percent over the 1995-96 level. The 50-percent increase

determined, a substantial amount of gas could be transported was the result of an additional 542 trillion Btu of capacity

by use of released capacity. For example, if all the capacity held in the West Region during 1996-97. The capacity held by

held by replacement shippers (Figure 24) were fully utilized, replacement shippers in the Midwest Region in 1996-97

36 percent of the 20.4 quadrillion Btu of gas delivered to increased by 280 trillion Btu, or 43 percent over the 1995-96

consumers during the 12 months ended March 31, 1997, level.

could have moved under released capacity.

The amount of capacity held by replacement shippers Central and Southwest regions experienced declines in 113

generally declines during the heating season, but it still capacity release activity. In the Central Region, the amount of

represents a sizeable amount. Based on capacity held, capacity held by replacement shippers decreased by 9 percent

replacement shippers could have moved 28 percent of the (128 trillion Btu) from the 1995-96 heating year level and the

10.4 quadrillion Btu of gas delivered to consumers during the number of capacity awards decreased by 52 percent

1996-97 heating season by using released capacity. These (1,911 fewer awards). While the declines in the Southwest

levels of released capacity 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, which had 44 percent of the they still represented significant percentage reductions for the

capacity held by replacement shippers, led other regions in regions (Figure 23).

the amount of capacity awarded during the year ended March

31, 1997 (Figures 23 and 24). The Southwest had the least The reduction in capacity release awards in certain regions

amount of capacity awards in a region; less than 1 percent of may not necessarily indicate a lack of available capacity in

the capacity held by replacement shippers occurred on those regions. For example, in the past few years the

pipeline companies that primarily serve the Southwest Region Southwest has experienced a series of capacity turnbacks in

(Figure 24). Although the amount of capacity awarded varied which primary shippers notified the pipeline companies of

between the heating and nonheating seasons, the regional their intent to reduce the amount of firm capacity reserved on

proportion of capacity held by replacement shippers was the systems. While the settlements in these cases resulted in

essentially the same as that for the 12-month period ended an allocation of the turnback costs among the parties, much of

March 1997. the physical space of the pipeline systems was no longer

Data from April 1994 through March 1997 indicate that the not have as much excess capacity to release on the market;

capacity release market provides a significant amount of however, it would not affect the total capability on the

access to transportation service in many areas of the United pipeline system. Since this excess capacity is no longer

States. However, these data do not indicate whether these reserved, shippers may be able to deliver more gas using

levels of capacity awards will be sustained or increase. There interruptible transportation service.

are indications that the market for released capacity in some

regions may be maturing while considerable growth may

continue in other regions. For example, the Northeast Region,

in addition to having the highest level of awarded capacity, is

experiencing substantial growth in the market for released

capacity. The amount of capacity held in the Northeast

increased by 977 trillion Btu, or 44 percent, between the

1995-96 and 1996-97 heating years (Figure 23). 

In contrast to the Northeast, West, and Midwest regions, the

reserved. The shippers that turned back the capacity would

Interruptible Transportation Service

A look at the utilization of interruptible service provides the

perspective needed to complete an assessment of

transportation deliverability. While amounts vary throughout

the year and across regions, interruptible service represents a

relatively constant share of national transportation throughput

(Figure 25). More than 4,700 trillion Btu (TBtu) of gas was

transported by use of interruptible service during the 1996-97

heating year (the 12 months ended March 31, 1997),

representing 16 percent of the 29,135 TBtu total

transportation throughput. 

The total volume of released capacity held by replacement shippers 113

during a season is the sum of the capacity effective on each day of the season.

For example, if a 60-day contract for Z thousand cubic feet per day is effective

within a season, then the sum of capacity held for the season would include Z

thousand cubic feet 60 times for that contract. If that 60-day contract were

only effective, for example, for the last 20 days of the season, then the sum for

the season would include Z thousand cubic feet 20 times, and the sum for the

next season would include Z thousand cubic feet 40 times for that contract.
 



  







 Central

534

(18.0%)

Western

556

(18.8%)

Southeast

113

(3.8%)

Southwest

21

(0.7%)

Midwest

428

14.5%

Northeast

1,309

(44.2%)

Total = 2,960 trillion Btu

Jan Apr Jul Oct Jan Apr Jul

0

1

2

3

4

1997

Transportation Volum e (Q uadrillion B tu)

Firm

Interruptible

1996















 



  







 Central

829

(18.9%)

Western

1,001

(22.8%)

Southeast

141

(3.2%)

Midwest

497

(11.3%)

Northeast

1,897

(43.2%)

Southwest

29

(0.7%)

Total = 4,395 trillion Btu

Energy Information Administration

86 Deliverability on the Interstate Natural Gas Pipeline System

Source: Energy Information Administration, Office of Oil and Gas, derived from Federal Energy Regulatory Commission, Electronic Data

Interchange (EDI) data.

Figure 24. Capacity Held by Replacement Shippers During the Nonheating and Heating Seasons, by

Region

(Trillion Btu)

1996-97 Heating Season (November - March)

Note: Throughput volumes exclude natural gas transported for storage.

Source: Energy Information Administration, Office of Oil and Gas, derived from Federal Energy Regulatory Commission, FERC Form 11,

“Natural Gas Pipeline Company Quarterly Statement of Monthly Data.”

Total 1996-97 Heating Year = 7,355 trillion Btu

1996 Nonheating Season (April - October)

Figure 25. Natural Gas Pipeline Throughput Under Firm and Interruptible Service,

January 1996 - September 1997
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 87

Even during the heating season, when capacity is more apt to  Industrial companies (including independent power

be constrained, almost 2,000 TBtu, or 15 percent, of gas producers, cogenerators, and commercial firms)

moved under interruptible service. The share of interruptible

service during the 1996-97 heating year varied across regions  Local distribution companies (including intrastate

from a low of 7 percent of total transportation in the West to pipeline companies and combination electric and natural

a high of 49 percent in the Southwest. The significant use of gas utilities for which natural gas is not the primary or

interruptible service clearly indicates that it represents a alternative source of fuel for generating electricity)

viable service option for shippers. Based on a 100-percent

load factor, interruptible service represented an average daily  Marketers

capacity of about 13 TBtu per day for the sample pipeline

companies.  Interstate pipeline companies

The future availability and use of interruptible service will in  Other (including producers, gatherers, and other

large part depend on the contracting practices of shippers. As companies).

the transportation market matures, terms or lengths of contract

agreements may become shorter. The likelihood that contracts Differences between these types of shippers were then

will be terminated upon reaching their expiration date will examined, focusing on the data for April 1, 1997. The

depend largely on the type, options, and requirements of the findings include:

shipper holding the contract.

 Local distribution companies (LDCs) held the largest

Characteristics of Firm Capacity

Held by Different Types of Shippers

Shippers will contract for firm pipeline capacity for different

quantities and terms, depending on the purpose for which the

gas is being moved. For example, a local distribution

company that is responsible for supplying the gas needs of

core residential and commercial customers is likely to have a

greater share of its transportation under firm contracts than an

industrial shipper that can use interruptible service or easily

switch to an alternate fuel. As another example of how

shipper’s needs differ, an industrial company, with welldefined and steady requirements for natural gas, may have

contracts with longer terms than those of a marketer who

values flexibility and needs to offer service to many types of

customers.

To examine these and other characteristics of firm capacity,

shippers were classified according to six different

categories:114

 Electric utilities (including combination electric and

natural gas utilities for which natural gas is the primary

or alternative source of fuel for generating electricity)

portion of firm capacity, 44 percent. This was more than

twice that of the next largest portion held by electric

utilities.

 Virtually all (96 percent) of the firm capacity was held

under long-term contracts (those with terms of 1 year or

more).

 The average lengths of the long-term contracts ranged

from 6.7 years for marketers to 11.9 years for pipeline

companies.

 Marketers held 75 percent of the firm capacity under

short-term contracts (those with terms of less than

1 year), while LDCs held the largest proportion of

capacity under long-term contracts, 46 percent.

 The average size of long-term contracts varied widely,

from 57.0 billion Btu per day per contract for pipeline

companies to 7.6 billion Btu per day for industrial

shippers.

 The greatest shares of total firm capacity were held in the

Northeast (36 percent) and the Midwest (25 percent).

LDCs held the largest proportion of firm capacity within

each region except for the Western Region, where

marketers held the largest share.

 New contracts that became effective April 1, 1996,

through April 1, 1997, accounted for 31 percent more

firm transportation capacity than was associated with

contracts that expired during the period.

The Index of Customers lists only the names of shippers without 114

identifying the company types. Thus, shipper types were identified by Energy

Information Administration (EIA) staff by cross-referencing shipper names

with other information sources and through Internet searches (see

Appendix D).
Energy Information Administration

88 Deliverability on the Interstate Natural Gas Pipeline System

Capacity and Contract Terms

Shippers held 101 trillion Btu per day of firm capacity on

April 1, 1997, based on the sample of pipeline companies

examined in this analysis (Table 15). The sample includes 115

63 interstate pipeline companies, 17 more than in the analysis

of transportation system access presented earlier in the

chapter. LDCs accounted for the largest portion of this

capacity, 44 percent (Figure 26), more than twice that of the

next largest portion, 21 percent, which was held by electric

utilities.

Industrial companies had the smallest share of firm capacity,

5 percent, but industrial companies probably had indirect

access to more firm capacity than is implied by this statistic.

As end users, industrial companies are likely to have had

access to other firm capacity through contracts with marketers

and LDCs or any of the other types of shippers listed.

Consider that in 1996, 5.5 quadrillion Btu of natural gas

consumed by industrial companies was delivered under firm

contracts. Assuming a 100-percent load factor, this is 116

equivalent to an average of 15 trillion Btu per day. On April

1, 1997, industrial companies held just over 5 trillion Btu per

day in firm capacity, which is only about one-third the

amount of actual firm consumption in 1996. One must use

caution when making direct comparisons between

consumption and capacity because companies must often

reserve capacity on different segments of a pipeline even

though not all segments are used for every delivery of natural

gas. Still, even this rough comparison shows that industrial

companies use more firm gas supplies than can be provided

through the firm capacity contracts they own directly.

The relative shares of firm capacity held by shippers are

similar whether it is the middle of the winter, when demand

for natural gas for space heating is high, or in the summer,

when capacity is more readily available and a shipper could

more likely receive interruptible service. On January 1, 1997,

LDCs held 43 percent of total firm capacity, and industrial

users held only 5 percent (total firm capacity was 108 trillion

Btu per day). On July 1, 1997, LDCs held 42 percent and

industrials held 6 percent of firm capacity (which totaled

94 trillion Btu per day).

Almost all of the firm capacity held by shippers on April 1,

1997, 96 percent, was held under long-term contracts (1 year

or longer). The overall average length of these contracts for

all shippers was 9.1 years. The distribution of long-term

capacity among the different types of shippers was almost

identical to that of total capacity—LDCs held the most,

46 percent, followed by electric utilities, which held

21 percent, and industrials held the least, 5 percent.

The average lengths of these long-term contracts were quite

varied among the different types of shippers (Figure 27).

Average terms ranged from 6.7 years for marketers, reflecting

their need for flexibility, to 11.9 years for pipeline companies.

Pipeline companies held a relatively small amount of the total

firm capacity, 6.6 trillion Btu, or 7 percent of the total. They

typically reserve capacity on other pipeline systems to assist

in the operational control of natural gas flows on their own

systems. Most pipeline companies have had decades of 117

experience in moving large volumes of gas. Their capacity

requirements are fairly stable over time and they are thus able

to benefit from longer length contracts. The average length of

long-term firm contracts held by LDCs, which had the largest

proportion of capacity, was 9.7 years.

The characterization of what type of shipper holds capacity

changes dramatically for short-term contracts (less than 1 year

long). Here, marketers held the overwhelming amount of

short-term capacity, 75 percent. The next largest share was

only 8 percent held by shippers in the “Other” category.

Industrial companies again held 5 percent of capacity, but in

this case they were only the second smallest group. Pipeline

companies held no short-term capacity at all. The 6.6 trillion

Btu per day of firm capacity held by pipeline companies was

all long term.118

The average length of short-term contracts 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 contracts, marketers still had 81 percent of their total

firm capacity of 17.5 trillion Btu per day under long-term

contracts as of April 1, 1997.

There are seasonal variations in the average length of shortterm contracts held by some types of shippers. For example,

as of January 1, 1997, a date toward the middle of the heating

season, both electric utilities and marketers held short-term

firm capacity contracts that averaged just over 5 months in

length, matching the length of the heating season. As of

The 63 pipeline companies included in this sample are those companies 115

that file Index of Customers (IOC) information with the Federal Energy Pipeline companies also retain control over a certain amount of capacity

Regulatory Commission for which there was complete and consistent on their own systems for purposes of operational control. These capacity

information for each of the quarters from April 1, 1996, to April 1, 1997. This amounts are not part of the data contained in the Index of Customers because

resulted in the exclusion of data for eight companies that file IOC information. pipeline companies are not considered to be shippers on their own systems.

Energy Information Administration, Natural Gas Annual 1996, Pipeline companies did hold short-term capacity contracts in all the 116

DOE/EIA-0131(96) (Washington, DC, September 1997), Table 22. other 3-month periods examined for this study.

117

118
 













 

 







 







 

LDCs

44.2

(43.8%)

Electric

Utilities

20.7

(20.5%)

Total firm capacity is 101 trillion Btu

Pipeline Companies

6.6

(6.5%)

Other

6.4

(6.3%)

Industrials

5.5

(5.4%)

Marketers

17.5

(17.4%)

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 89

Figure 26. Share of Total Firm Capacity Held on April 1, 1997, by Type of Shipper

(Capacity in Trillion Btu per Day)

LDC = Local distribution company.

Note: Sum of percentage does not equal 100 percent because of independent rounding.

Source: Energy Information Administration, Office of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of

Customers.

Table 15. Characteristics of Firm Contract Capacity as of April 1, 1997, by Shipper

All Contracts Long-Term Contracts Short-Term Contracts a b

Shipper Type Capacity Number Average Capacity Number Average Capacity Number Average

(trillion Btu of Term (trillion Btu of Term (trillion Btu of Term

per day) Contracts (years) per day) Contracts (years) per day) Contracts (months)

Electric Utility 20.7 645 10.1 20.4 620 10.5 0.2 25 2.6

Industrial 5.5 739 7.1 5.3 690 7.6 0.2 49 2.2

LDC 44.2 2,544 9.5 43.9 2,486 9.7 0.3 58 3.5

Marketer 17.5 938 5.1 14.2 704 6.7 3.3 234 4.0

Other 6.4 349 7.7 6.1 293 9.1 0.3 56 2.6 c

Pipeline Company 6.6 115 11.9 6.6 115 11.9 0.0 0 NA

Total 100.8 5,330 8.4 96.4 4,908 9.1 4.4 422 3.5

Long-term contracts are for 1 year or longer. a

Short-term contracts are for less than 1 year. b

Other includes producers, gatherers, and those shippers for which a category could not be determined. c

LDC = Local distribution company. NA = Not available.

Note: Totals may not equal sum of components because of independent rounding.

Source: Energy Information Administration, Office of Oil and Gas, derived from Federal Regulatory Energy Commission (FERC) Index of

Customers.
Industrials

LDCs

Marketers

Years

Pipeline

Companies

All 

Shippers

0 2 4 6 8 10 12 14

10.5

7.6

9.7

6.7

9.1

11.9

9.1

Electric

Utilities

Other

Energy Information Administration

90 Deliverability on the Interstate Natural Gas Pipeline System

LDC = Local distribution company.

Note: Long-term contracts are for 1 year or longer.

Source: Energy Information Administration, Office of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of

Customers.

Figure 27. Average Length of Long-Term Firm Contracts as of April 1, 1997

April 1, 1997, the beginning of the refill season, the average When considering the long-term contracts, LDCs held the

length of short-term contracts fell to 2.6 months for electric greatest total amount of firm daily capacity, yet the average

utilities and to 4.0 months for marketers (Figure 28). capacity per contract for LDCs was much lower than for

The average length of short-term contracts declined between Also, the average daily capacity of LDC contracts,

January and April because of the increased proportion of 17.7 billion Btu, was close to, but still smaller than that of

contracts with terms of 1 month or less as the heating season contracts held by both marketers and companies in the Other

ended. For example, as of January 1, 1997, electric utilities category. Pipeline companies held the highest capacity longdid not hold any short-term capacity under contracts that were term contracts, averaging 57.0 billion Btu per day per

for terms of 1 month or less; however, as of April 1, 1997, contract. Even though pipeline companies held a relatively

38 percent of their total short-term capacity was under 30-day small proportion of total firm capacity, the large amount of

contracts. The situation is similar for marketers, who on capacity per contract may reflect their role as movers of large

January 1, 1997, held only 6 percent of short-term capacity volumes of gas from producing to consuming areas of the

under contracts for 1 month or less but held 25 percent of country. Electric utilities held the second highest capacity

their short-term capacity under such contracts on April 1, contracts, averaging 33.0 billion Btu per day per contract. The

1997. smallest contracts, averaging 7.6 billion Btu per day each,

Total capacity held by different types of shippers provides

one view of the firm capacity market, but the average capacity

per contract provides another view of the contracting

practices of firm shippers. For all types of shippers, the

average amount of capacity under long-term contracts is

much larger than under short-term contracts, reflecting the

general use of short-term firm capacity to meet incremental

loads or to meet unexpected demand.

either pipeline companies or electric utilities (Figure 29).

were held by industrial companies.

Regional Shipper Characteristics

Shippers hold the most firm capacity in those regions with

larger populations and colder temperatures and that are

farthest away from both domestic and Canadian sources of

supply—the Northeast and the Midwest. LDCs, which are
Electric

Utilities

Industrials

LDCs

Marketers

Other

Pipeline

Companies

All

Shippers

a

20 40 60

33.0

7.6

17.7

20.2

20.7

57.0

19.6

9.9

4.5

5.4

14.2

5.9

10.5

Billion Btu per Day

Long Term

S hort Term

0

Electric

Utilities

Industrials

LDCs

Marketers

Other

Pipeline

Companies

All

Shippers

a

246

5.1

3.2

3.7

5.2

3.8

3.0

4.5

2.6

2.2

3.5

4.0

2.6

3.5

Months

As of January 1, 1997 As of April 1, 1997

0

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 91

Pipeline companies did not have any contracts for short-term firm capacity on April 1, 1997. a

LDC = Local distribution company.

Notes: Long-term contracts are for 1 year or longer. Short-term contracts are for less than 1 year.

Source: Energy Information Administration, Office of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of

Customers.

Pipeline companies did not have any contracts for short-term, firm capacity on April 1, 1997. a

LDC = Local distribution company.

Note: Short-term contracts are for less than 1 year.

Source: Energy Information Administration, Office of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of

Customers.

Figure 29. Average Firm Capacity per Contract as of April 1, 1997

Figure 28. Average Length of Short-Term Firm Contracts, January and April 1997
 



 









 









 







LDCs

4.1

(29.3%)

Electric Utilities

3.6

(26.2%)

Other

2.6

(18.6%) Marketers

2.3

(16.2%)

Pipeline

Companies

0.8

(6.1%)

Industrials

0.5

(3.6%)

Total firm capacity is 14 trillion Btu 







 









 

 



  

 

LDCs

3.3

(62.6%)

Electric Utilities

0.8

(15.9%)

Total firm capacity is 5 trillion Btu 

Industrials

0.6

(11.7%)

Marketers

0.2

(4.3%)

Other

0.2

(3.6%)

Pipeline

Companies

0.1

(1.9%)

Energy Information Administration

92 Deliverability on the Interstate Natural Gas Pipeline System

LDC = Local distribution company.

Source: Energy Information Administration, Office of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of

Customers.

Central Region Southeast Region

Figure 30. Share of Regional Firm Capacity as of April 1, 1997, by Shipper for Selected Regions

(Capacity in Trillion Btu per Day)

often the only source of natural gas for weather-sensitive 21.3 trillion Btu (TBtu), or 59 percent of regional firm daily

residential and commercial users, held the largest proportion capacity. This was nearly three times the 7.2 TBtu held by the

of firm capacity in almost every region, sometimes far second-place electric utilities in the Northeast. In the

exceeding that held by the second largest shipper in the Midwest, LDCs held 8.6 TBtu of firm daily capacity, or 34

region. Electric utilities (which include combination electric percent of the regional total. Marketers played a greater role

and gas utilities) and marketers also tend to hold larger shares as holders of firm capacity in this region, having the second

of regional firm capacity compared with other types of highest level, at 5.8 TBtu (23 percent of the regional total). In

shippers. the Northeast, marketers held only 8 percent of regional firm

Of the 101 trillion Btu per day in firm capacity held on April

1, 1997, the largest share, 36 percent, was held on pipelines The Central Region had the most uniform distribution of

that deliver most of their gas in the Northeast Region. The contracted capacity among the different types of shippers

next largest share, 25 percent, was in the Midwest. These (Figure 30). In part, this may be because the natural gas

regions rank first and third, respectively, 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 consumption within the

second coldest, respectively, in 1996 (Table 10, Chapter 4). region. The Central Region acts as a conduit of gas from

These two regions alone accounted for 58 percent of the total Canada. LDCs still held the largest share of regional firm

residential and commercial consumption of natural gas in capacity, 29 percent, but shippers in the Other category,

1996 (Table 12, Chapter 4), and LDCs held the largest share which includes producers, held the third largest proportion,

of firm capacity in both regions. In the Northeast, LDCs held 19 percent.

capacity.

Rocky Mountain producers and for some imports from
0 1 2 3 4 5 6 7 8 9 10

2.7

0.8

4.2

4.8

2.2

0.7

1.2

0.7

1.8

3.1

0.4

0.3

Trillion Btu per Day

New Contracts

Expiring Contracts

Electric

Utilities

Industrials

LDCs

Marketers

Other

Pipeline

Companies

0 1 2 3 4 5 6 7 8 9 10

1.0

1.1

1.2

9.0

1.1

1.7

1.1

1.2

1.7

9.3

1.3

1.2

Trillion Btu per Day

New Contracts

Expiring Contracts

Electric

Utilities

Industrials

LDCs

Marketers

Other

Pipeline

Companies

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 93

Figure 31. Capacity Under New and Expiring Firm Contracts, April 1, 1996 - April 1, 1997

Short Term Long Term

LDC = Local distribution company.

Notes: Short-term contracts are for less than 1 year. Long-term contracts are for 1 year or longer. 

Source: Energy Information Administration, Office of Oil and Gas, derived from Federal Energy Regulatory Commission (FERC) Index of

Customers.

The Southeast Region had the greatest concentration of of shippers when it comes to contract expiration or the

contracted capacity assigned to a single type of shipper. The initiation of new contracts, data from the Index of Customers

3.3 TBtu per day held by LDCs accounted for 63 percent of were examined for the 12-month period of April 1, 1996

the regional total and was approximately four times the through April 1, 1997. During this time, new contracts for

amount held by the shippers in second place, electric utilities 30.4 trillion Btu (TBtu) per day of firm transportation

(16 percent). The high concentration of capacity held by capacity became effective, while contracts accounting for

LDCs may be caused by two circumstances that exist in the 23.1 TBtu per day expired. Thus, newly contracted capacity

Southeast Region. First, many of the LDCs whose service exceeded expiring capacity by 31 percent. Marketers

areas are in the Northeast Region hold capacity on Southeast accounted for the largest shares of both new and expiring

pipelines. Second, the Southeast may not have implemented capacity, but the relative shares among the different types of

retail unbundling initiatives to the same extent as other shippers varied, depending on whether the contracts were

regions. Thus, LDCs must continue to serve the majority of short- or long-term.

customers’ needs. This would also explain the low share of

firm capacity held by marketers in this region, only 4 percent. Marketers totally dominated short-term capacity under both

In contrast, marketers held the largest proportion of firm Marketers accounted for 60 percent of the 15.0 TBtu per day

capacity in the Western Region, 33 percent (4.8 TBtu per of new short-term firm capacity and for 59 percent of the

day). The Western Region includes California, where retail 15.7 TBtu per day of expiring capacity. The shippers with the

unbundling began as early as 1986. In the West, electric next largest share of new short-term capacity were the

utilities held the second highest proportion of firm capacity, pipeline companies, with 11 percent of the total. For the

27 percent, followed closely by LDCs with 26 percent. expiring contracts, LDCs held the next largest share, which

New and Expiring Long-Term Contracts

Contract expiration is of particular interest in the natural gas

industry today. To see if there are differences between types

119

new and expiring contracts during the period (Figure 31).

was also 11 percent.

New contracts are those that started any time from April 2, 1996, 119

through April 1, 1997. Expiring contracts are those that ended any time from

April 1, 1996, through March 31, 1997.
Firm Contracted

Capacity (100 TBtu/d)

Released

Capacity (20 TBtu/d)

Unsubscribed

Capacity (27 TBtu/d)

Total

Capability

(127 TBtu/d)

Uncommitted and Unused

by Firm Shippers

Capacity Used by IT

by Firm Shippers

Committed but Unused

by Firm Shippers

Available Capacity

Utilization

Released Capacity

Used by Firm Shippers

Firm Contracted Capacity

Used by Firm Shippers

Capacity

Estimated

Utilized 

(80 TBtu/d)

Capacity

(47 TBtu/d)

Released but Unused

Energy Information Administration

94 Deliverability on the Interstate Natural Gas Pipeline System

Figure 32. Reserved, Utilized, and Available Capacity for the 1996-97 Heating Year

TBtu/d = Trillion Btu per day. IT = Interruptible transportation service.

Note: A firm shipper is one using firm transportation services.

Source: Energy Information Administration, Office of Oil and Gas.

Capacity under new short-term contracts was almost equal to expiring contracts. With 2.7 TBtu, electric utilities held

that under expiring contracts during the period, but for long- 18 percent of the new, long-term daily capacity that became

term contracts, new capacity was more than double that under effective during the period.

expiring contracts. Thus, shippers showed a preference for

longer term contracts as they increased their holdings of firm

transportation capacity during the period. New long-term

contracts accounted for 15.4 TBtu per day of firm capacity,

while long-term contracts for 7.5 TBtu of daily capacity

expired. As with short-term contracts, marketers held the

largest shares of both new and expiring capacity under longterm contracts, but both LDCs and electric utilities also held

significant shares of each.

Marketers held 4.8 TBtu per day of firm capacity under new

long-term contracts, 31 percent of the total. This new capacity

was 56 percent more than that held by marketers under

expiring contracts during the period. LDCs held 4.2 TBtu per

day of new capacity under long-term contracts, accounting for

27 percent of the total. The new capacity held by LDCs was

more than double that held under expiring contracts. New

capacity held by electric utilities during the period was also

more than double the amount held by these shippers under

Summary

The unused capability of the interstate pipeline system for

transportation service appears to be substantial. Based on an

estimated maximum system capability of 127 trillion Btu

(TBtu) per day, on average, 37 percent or 47 TBtu per day of

the pipeline system capability was unused during the 1996-97

heating year (Figure 32). Shippers using firm transportation

services accounted for an average of 67 TBtu of gas per day,

utilizing only 53 percent of the system capability and only 67

percent of the reserved capacity during the 1996-97 heating

year. This allowed interruptible shippers to move an average

of 13 TBtu per day, which represented 10 percent of the

system capability. While 100 TBtu per day, or 78 percent of

the system capability, was reserved during 1996-97, 20 TBtu

of that was released to other firm shippers.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 95

Transportation access during the heating season was less than Whether these levels of unsubscribed and accessible capacity

the 12-month average, but market conditions indicate that the remain unchanged in the future will largely depend on what

system can support significant additional load during this happens when firm transportation capacity contracts come up

period as well. On average, 31 percent or 39 TBtu per day of for renewal. If significant capacity is turned back to the

the pipeline system capability was unused during the 1996-97 system, shippers may respond by transporting more gas using

heating season. An average of 75 TBtu of gas per day was interruptible service.

transported under firm transportation services, utilizing

59 percent of the system capability and 70 percent of the As of April 1997, virtually all (96 percent) of the firm

reserved capacity. Interestingly, interruptible service capacity capacity was held under long-term contracts (those with terms

utilization during the heating season was at the same level as of 1 year or more), with local distribution companies holding

during the nonheating season, 13 TBtu per day. The amount the largest portion of firm capacity, 44 percent. The greatest

of reserved capacity increased to 107 TBtu per day during the shares of total firm capacity were held in the Northeast

heating season, but 20 TBtu per day was still released to (36 percent) and the Midwest (25 percent).

secondary shippers. 
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 97

Appendix A

State-to-State Natural Gas Pipeline Capacity

 and Usage Levels

This appendix presents data on State-to-State capacity and more than one branch or mainline segment crossing to another

usage levels for major interstate pipeline companies in 1996 State. In such cases, data for the several points are combined

and the percentage change between 1990 and 1996. The and summed rather than being separately identified in the table.

appendix consists of six maps and six tables, which correspond Data regarding any of these individuals points, if wanted, are

to the six U.S. geographic regions used throughout the report available within the supporting database.

(Alaska, the District of Columbia, and Hawaii are not

included). The six regions are defined and ordered as follows: (The data contained in the tables may be downloaded from the

 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. lications/deliverability/data. The format and data element

 Midwest Region - Illinois, Indiana, Michigan, Minnesota, be found in the EIAGIS-NG (see Appendix C) data dictionary

Ohio, and Wisconsin. DATADICT. DBF, also available from these sites.)

 Northeast Region - Connecticut, Delaware, Maine, For each adjoining State, a summary line displaying the

Maryland, Massachusetts, New Hampshire, New Jersey, combined total capacity, 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

 Southeast Region - Alabama, Florida, Georgia, cases, no flow data were reported in 1996 for a known State-toKentucky, Mississippi, North Carolina, South Carolina, State pipeline combination. In these cases, the capacity value

and Tennessee. for the route is not included as part of the denominator

 Southwest Region - Arkansas, Louisiana, New Mexico, and regional summary levels were calculated.

Oklahoma, and Texas.

 Western Region - Arizona, California, Idaho, Nevada, of the maximum throughput capability of the interstate natural

Oregon, and Washington. gas pipeline network at a regional or State boundary.

Each regional map portrays the States included in the region transported under normal operating conditions for a sustained

and the approximate routes of the major interstate pipelines period of time. Information on capacity levels for the interstate

operating in the region. Routes of some of the smaller pipeline pipeline systems was compiled by using data available from

systems are not displayed because they are difficult to filings at the Federal Energy Regulatory Commission (FERC)

distinguish from the major systems. Underground storage site and through contacts with the companies themselves.

locations are included in the maps to give the reader a

perspective on the proximity and accessibility of storage to The average daily flow volumes presented in Tables A1

pipelines within a region. Although the maps do not include through A6 are based upon 1996 data extracted from Form

capacity levels, the reader can find a mapped regional State-to- EIA-176, “Annual Report of Natural and Supplemental Gas

State capacity summary representation in Chapters 3 and 5 of Supply and Disposition.” They are the sum of data that can be

the report. identified as volumes brought across a border. The data on

Each table represents one region, with the States within the on a 366-day basis (1996 was a leap year). More information

region presented in alphabetical order. For each State, a line on how Form EIA-176 data were compiled and included in this

item is listed for each interstate pipeline company capable of report can be found in Appendix D.

transporting gas from an adjoining State. It should be noted

that in a number of instances a pipeline company may have

Energy Information Administration’s (EIA) Internet site in

definitions for the STBORDER database and spreadsheet can

receiving State is presented for each of these values. In some

(weighting factor) when average utilization rates at the State

The measure of capacity that is shown represents an estimate

Specifically, it is an estimate of how much gas can be

Form EIA-176 are annual; average daily levels were computed
Energy Information Administration

98 Deliverability on the Interstate Natural Gas Pipeline System

Figure A1. Major Interstate Natural Gas Pipelines in the Central Region

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, as of December 1997.
Table A1. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Central Region, by State, 1990 and 1996

(Volumes in Million Cubic Feet per Day)

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 99

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Colorado

Colorado Interstate Gas Kansas 340 0 0 -- -- -- Kansas 244 c

Panhandle Eastern P L Co 45 0 0 -- -- -- None

Total 385 0 0 -- -- -- 

KN Interstate Gas Co Nebraska 97 144 2 -90 2 -96 Kansas/NE 60 c

Trailblazer Pipeline Co 500 0 490 141 98 141 Nebraska 500

Total 597 11 492 123 82 102

Transwestern Pipeline Co New Mexico 276 84 0 -- -- -- New Mexico 500 c

Colorado Interstate Gas Oklahoma 200 0 71 -- 35 -- Oklahoma 250 c

Colorado Interstate Gas Utah 165 104 -- 63 -- Wyoming 180 d

Northwest Pipeline Corp 337 60 84 100 25 25 Utah 587 c

Questar P L Co 23 0 2 -93 10 -93 None c

Total 525 125 190 164 36 17

Colorado Interstate Gas Wyoming 625 0 554 12 89 12 Oklahoma 250

Questar P L Co 313 6 0 -- -- -- None c

Williams Natural Gas Co 178 24 146 15 82 -7 Kansas 186

Wyoming Interstate Co 499 0 480 123 96 123 None

Total 1,615 3 1,180 35 91 62

Total 3,597 17 1,934 46 74 49

Iowa

Northern Border Pipeline Co Minnesota 1,575 42 1,541 61 98 13 None

ANR Pipeline Co Missouri 680 13 669 17 99 4 Illinois 603

Nat Gas P L Co of America Nebraska 1,330 0 1,067 14 80 14 Illinois 1,665

Northern Natural Gas Co 1,295 0 740 33 57 20 Minnesota/IL/SD 2,035

Total 2,625 0 1,801 21 69 15

Total 4,880 13 4,019 33 82 15

Kansas

Colorado Interstate Gas Colorado 244 0 83 15 34 15 Colorado 340 c

KN Interstate Gas Co 20 0 13 63 66 63 Nebraska 81

Williams Natural Gas Co 186 19 164 15 88 -4 Nebraska 6

Total 450 7 261 16 58 9

KN Interstate Gas Co Nebraska 40 0 4 17 9 -12 None c

ANR Pipeline Co Oklahoma 853 0 697 16 82 16 Nebraska 693

Nat Gas P L Co of America 1,153 0 689 -8 60 -8 Nebraska 1,175 c

Noram Gas Transmission Co 40 -20 18 -13 45 8 None

Northern Natural Gas Co 1,330 0 546 38 41 5 Nebraska 2,050

Panhandle Eastern P L Co 1,395 -5 834 62 60 71 Missouri 1,559

Transwestern Pipeline Co 5 0 2 -20 32 -20 None

Williams Natural Gas Co 496 0 280 -17 56 -17 Missouri/OK 1,231

Total 5,272 -2 3,067 17 58 18

Total 5,762 -1 3,331 17 58 17

Missouri

Associated Natural Gas Co Arkansas 10 0 9 50 88 54 Arkansas 30

Mississippi River Trans Corp 730 0 339 29 46 29 Illinois 590

Nat Gas P L Co of America 1,650 4 1,184 30 72 25 Illinois 1,650

Noram Gas Transmission Co 100 -33 15 -21 15 18 None

Texas Eastern Trans Corp 324 0 264 100 81 100 Illinois 300

Total 2,814 1 1,811 37 64 36

Mississippi River Trans Corp Illinois 695 10 0 -- -- -- None
Table A1. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Central Region, by State, 1990 and 1996 (Continued)

(Volumes in Million Cubic Feet per Day)

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Energy Information Administration

100 Deliverability on the Interstate Natural Gas Pipeline System

Panhandle Eastern P L Co Kansas 1,559 -2 1,447 18 93 21 Illinois 1,361

Williams Natural Gas Co 972 0 262 11 27 11 None

Total 2,531 -1 1,710 17 68 18

ANR Pipeline Co Nebraska 693 14 679 17 98 3 Iowa 680

Williams Natural Gas Co Oklahoma 47 0 45 22 96 22 None

Total 6,780 2 4,244 25 70 23

Montana

Montana Power Co Canada 64 25 64 144 97 89 Canada 6

Northern Border Pipeline Co 1,489 39 1,475 79 99 26 North Dakota 1,480

Northern Natural Gas Co 10 -92 5 -100 -- -- Canada 60

Total 1,563 25 1,542 67 98 31

Williston Basin I P L Co North Dakota 268 17 28 -48 10 -56 North Dakota 304 c

Colorado Interstate Gas Wyoming 60 -- -- -- -- -- None c

Montana Power Co 2 0 0 -53 12 -53 None

Williston Basin I P L Co 188 43 47 90 25 16 Wyoming 162 c

Total 250 88 47 87 25 15

Total 2,081 29 1,617 58 80 25

Nebraska

KN Interstate Gas Co Colorado 40 0 3 -44 8 -44 None c

Trailblazer Pipeline Co 500 0 491 137 98 137 Colorado 500

Total 540 0 494 132 91 132

ANR Pipeline Co Kansas 693 14 679 17 98 3 Missouri 693

KN Interstate Gas Co 81 0 12 -52 15 -52 Colorado 96 c

Nat Gas P L Co of America 1,176 -30 712 -10 61 30 Iowa 1,330

Northern Natural Gas Co 2,050 0 974 26 47 26 Iowa/SD 1,365

Williams Natural Gas Co 6 0 2 -10 36 -10 None

Total 4,005 -10 2,379 10 59 22

KN Interstate Gas Co Wyoming 120 -12 109 42 90 63 None

Trailblazer Pipeline Co 500 0 490 141 98 141 Colorado 500

Total 620 -3 599 114 97 119

Total 5,165 -8 3,472 31 67 42

North Dakota

Viking Gas Transmission Co Minnesota 84 223 22 21 26 -62 None

Northern Border Pipeline Co Montana 1,480 38 1,472 59 99 20 South Dakota 1,685

Williston Basin I P L Co 5 139 87 290 29 63 Montana 268 c

Total 1,785 48 1,559 70 90 15

Williston Basin I P L Co South Dakota 53 166 -- -- -- -- None

Total 1,922 54 1,581 64 85 97

South Dakota

Northern Natural Gas Co Iowa 30 0 2 -58 5 -58 None

Northern Natural Gas Co Nebraska 70 0 34 26 48 26 None

Northern Border Pipeline Co North Dakota 1,675 38 1,656 52 99 10 Minnesota 1,655

Williston Basin I P L Co 4 3 22 -16 40 -19 None c

Total 1,729 37 1,677 51 97 16

Williston Basin I P L Co Wyoming 27 3 0 0 -- -- None c

Total 1,856 33 1,793 57 97 155
Table A1. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Central Region, by State, 1990 and 1996 (Continued)

(Volumes in Million Cubic Feet per Day)

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 101

Utah

Northwest Pipeline Corp Colorado 337 105 0 -- -- -- Colorado 366 c

Questar P L Co 51 0 42 39 83 39 Wyoming 269 c

Total 388 81 42 -60 83 39

Northwest Pipeline Corp Idaho 298 19 0 -100 -- -- Wyoming 360 c

Kern River Gas Trans Co Wyoming 831 -- 739 -- 89 -- Nevada 750

Northwest Pipeline Corp 430 0 72 9 17 9 Colorado 310 c

Questar P L Co 704 3 233 -10 33 -13 Colorado 23 c

Total 1,965 76 1,044 220 53 82

Total 2,651 68 1,086 73 54 35

Wyoming

Colorado Interstate Gas Colorado 180 -- 146 -- 81 -- Colorado 625

Questar P L Co 165 175 46 27 28 -54 Utah 703 c

Trailblazer Pipeline Co 500 0 490 141 98 80 Nebraska 500

Total 845 51 682 184 81 74

Colorado Interstate Gas Montana 60 -- 0 0 -- -- None c

Williston Basin I P L Co 163 0 0 -- -- -- Montana 188 c

Total 223 37 0 -- -- -- 

Williston Basin I P L Co South Dakota 26 13 0 -- -- -- None c

Northwest Pipeline Corp Utah 360 44 0 -- -- -- Utah 310 c

Questar P L Co 269 0 46 113 94 113 Colorado 312 c

Total 629 21 46 -68 94 248

Total 1,723 36 728 71 79 135

Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. a

Average usage rate is equal to the average daily flow derived by estimated capacity. Utilization computation does not include capacity against b

which no flow was reported.

Bidirection flow occur on some or all of the pipeline company lines that cross the State border. The value shown represents the capacity, or c

sum of capacity, for only the flow in the direction indicated.

Less than 0.5 percent and greater than -0.5 percent. d

-- = Not applicable, pipeline not in service in 1990 and/or no flow reported in 1990 or 1996.

Note: Totals may not equal sum of components because of independent rounding.

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity

Database, as of December 1997.
Energy Information Administration

102 Deliverability on the Interstate Natural Gas Pipeline System

Figure A2. Major Interstate Natural Gas Pipelines Serving the Midwest Region

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, as of December 1997.
Table A2. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Midwest Region, by State, 1990 and 1996

(Volumes in Million Cubic Feet per Day)

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 103

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Illinois

ANR Pipeline Co Indiana 1,250 0 0 -100 -- -- Indiana 1,249 c

Midwestern Gas Trans Co 650 356 1 55 1 None d

Texas Gas Trans Corp 44 5 24 16 55 10 None

Total 1,944 0 380 -27 54 -1

ANR Pipeline Co Iowa 653 27 617 45 94 14 Wisconsin 581

Natural Gas PL Co of America 1,665 0 1,428 31 86 30 Wisconsin 55

Northern Natural Gas Co 635 20 506 66 80 38 Wisconsin 385

Total 2,953 9 2,552 40 86 28

Trunkline Gas Co Kentucky 1,799 0 1,241 22 69 22 Indiana 745

Mississippi River Trans Corp Missouri 590 0 50 -60 8 -60 Missouri 695

Natural Gas P L Co of America 1,650 6 1,175 31 71 23 None

Panhandle Eastern P L Co 1,361 0 1,304 17 96 17 Indiana 1,573

Texas Eastern Trans Corp 300 24 246 115 82 73 Indiana 400

Total 3,901 4 2,775 23 71 18

ANR Pipeline Co Wisconsin 550 0 177 -- 32 -- None c

Total 11,147 4 7,124 27 72 31

Indiana

ANR Pipeline Co Illinois 1,250 0 587 -- 47 -- None c

Natural Gas P L of America 600 0 560 2 93 2 None

Panhandle Eastern P L Co 1,573 1 1,378 21 88 20 Ohio 1,313

Texas Eastern Trans Corp 400 133 293 155 73 10 Ohio 671

Trunkline Gas Co 745 0 705 47 95 47 None

Total 4,568 5 3,523 54 77 4

ANR Pipeline Co Kentucky 1,386 5 1,198 23 86 16 Ohio/IL 2,997

Midwestern Gas Trans Co 664 0 426 20 64 20 Illinois 649

Texas Gas Trans Corp 1,510 0 1,076 33 71 33 Illinois/OH 1,051

Total 3,560 2 2,700 26 76 24

ANR Pipeline Co Michigan 1,417 11 0 0 -- -- None c

ANR Pipeline Co Ohio 318 0 75 -- 24 -- Michigan 1,470 c

Panhandle Eastern P L Co 150 0 0 0 -- -- None

Total 468 0 75 -- 24 --

Total 10,012 5 6,299 42 75 11

Michigan

Bluewater Pipeline Co Canada 250 -- 0 -- 0 -- Canada 250 c

ANR Pipeline Co Indiana 1,470 20 617 -- 42 -- Indiana 1,417 c

Trunkline Gas Co 739 0 573 38 78 38 None

Total 2,209 12 1,190 186 54 4

ANR Pipeline Co Ohio 932 0 449 -16 48 -16 Indiana/OH 

Panhandle Eastern P L Co 860 -22 509 15 59 47 Canada 100

Total 1,792 -12 958 -2 53 11

Great Lakes Gas Trans Ltd Wisconsin 2,100 42 1,913 50 91 6 Canada 1,980

Northern Natural Gas Co 125 0 83 61 66 61 None

Total 2,225 39 1,996 50 90 8

Total 6,476 16 4,144 52 64 3

Minnesota

Central Pipeline Co Canada 88 0 39 -- 44 -- Canada 63

Great Lakes Gas Trans Ltd 2,286 37 2,143 48 94 8 Wisconsin 2,100

Viking Gas Transmission Co 425 5 399 41 94 35 Wisconsin/ND 431

Total 2,799 30 2,581 49 92 10
Table A2. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Midwest Region, by State, 1990 and 1996 (Continued)

(Volumes in Million Cubic Feet per Day)

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Energy Information Administration

104 Deliverability on the Interstate Natural Gas Pipeline System

Northern Natural Gas Co Iowa 1,370 4 742 38 54 33 Wisconsin 232

Northern Border Pipeline Co South Dakota 1,655 36 1,645 54 99 13 Iowa 1,575

Northern Natural Gas Co Wisconsin 70 600 4 -- 5 -- None

Total 5,894 25 4,972 49 84 16

Ohio

ANR Pipeline Co Indiana 1,748 0 1,151 111 70 111 Michigan/IN 1,250 c

Crossroads Pipeline Co 250 -- 92 -- 37 -- None

Panhandle Eastern P L Co 1,314 0 793 -1 60 -1 Michigan 860

Texas Eastern Trans Corp 671 27 287 8 43 -15 None

Texas Gas Trans Corp 1,007 0 796 38 79 38 None

Total 4,990 9 3,119 43 64 31

Columbia Gas Trans Corp Kentucky 574 0 450 -- 78 -- None

Tennessee Gas Pipeline Co 1,777 6 1,667 59 94 23 Pennsylvania 1,575

Texas Eastern Trans Corp 2,066 0 1,919 32 93 17 West Virginia 2,740

Union Light Heat & Power Co 45 13 43 34 96 7

Total 4,462 2 4,080 43 91 34

CNG Trans Corp Pennsylvania 435 0 4 -- 1 -- None

Columbia Gas Trans Corp 30 88 3 -82 10 -90 None

Total 465 3 7 -55 2 -56

CNG Trans Corp West Virginia 709 0 135 -28 19 -28 Pennsylvania 560

Columbia Gas Trans Corp 864 0 767 50 89 50 West Virginia 11 c

Total 1,573 0 902 29 57 29

Total 11,489 5 8,108 38 71 27

Wisconsin

ANR Pipeline Co Illinois 1,268 0 172 -46 14 -46 Illinois 550 c

Natural Gas PL Co of America 55 0 70 42 93 4 None

Northern Natural Gas Co 385 40 276 122 72 59 Michigan 125

Total 1,708 7 500 1 29 -6

ANR Pipeline Co Michigan 735 0 382 -- 52 -- None

Great Lakes Gas Trans Ltd Minnesota 2,100 42 1,921 50 91 5 Michigan 2,100

Northern Natural Gas Co 232 0 133 30 57 30 None

Viking Gas Transmission Co 347 2 327 30 94 27 None

Total 2,679 31 2,381 46 89 9

Total 5,122 17 3,263 53 64 8

Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. a

Average usage rate is equal to the average daily flow derived by estimated capacity. Utilization computation does not include capacity against b

which no flow was reported.

Bidirection flow occur on some or all of the pipeline company lines that cross the State border. The value shown represents the capacity, or c

sum of capacity, for only the flow in the direction indicated.

Less than 0.5 percent and greater than -0.5 percent. d

-- = Not applicable, pipeline not in service in 1990 and/or no flow reported in 1990 or 1996.

Note: Totals may not equal sum of components because of independent rounding.

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity

Database, as of December 1997.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 105

Figure A3. Major Interstate Natural Gas Pipelines Serving the Northeast Region

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, as of December 1997.
Table A3. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Northeast Region, by State, 1990 and 1996

(Volumes in Million Cubic Feet per Day)

Energy Information Administration

106 Deliverability on the Interstate Natural Gas Pipeline System

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Connecticut

Tennessee Gas Pipeline Co Massachusetts 81 0 7 -5 8 -5 Massachusetts 80 c

Algonquin Gas Trans Co New York 1,030 10 565 12 55 2 Rhode Island 665

Iroquois Pipeline Co 420 -- 389 -- 93 -- New York 260

Tennessee Gas Pipeline Co 121 4 101 -8 84 -12 None

Total 1,571 50 1,056 72 67 15

Total 1,652 46 1,063 71 64 17

Delaware

Eastern Shore Nat Gas Co Maryland 28 0 0 -- -- -- None

Columbia Gas Trans Corp Pennsylvania 172 48 34 42 20 -4 New Jersey 141

Eastern Shore Nat Gas Co 60 171 43 516 72 127 Maryland 10

Transcontinental Gas P L Co 76 27 50 31 65 3 None

Total 308 55 126 84 41 19

Total 336 48 126 35 41 -1

Maine

Granite State Gas Trans Inc New Hampshire 31 50 16 46 52 -43 New Hampshire 31

Total 31 50 16 46 52 -43

Maryland

Eastern Shore Nat Gas Co Delaware 10 0 9 21 85 21 Delaware 28

CNG Trans Corp Pennsylvania 533 29 117 95 22 51 Virginia 350

Columbia Gas Trans Corp 42 0 0 0 -- -- None

Eastern Shore Nat Gas Co 28 0 0 -- -- -- None

Texas Eastern Trans Corp 163 -- -- -- -- Pennsylvania 163 c d

Total 953 25 117 43 22 19

Columbia Gas Trans Corp Virginia 1,113 18 448 -1 40 -16 Pennsylvania 146

Transcontinental Gas P L Co 2,100 1,835 -5 87 -5 Pennsylvania 2,050 d

Total 3,213 6 2,283 -4 71 -9

Columbia Gas Trans Corp West Virginia 4 0 0 -- -- -- None

Total 4,170 8 2,409 -2 64 -9

Massachusetts

Tennessee Gas Pipeline Co Connecticut 80 0 0 -- -- -- None None

Tennessee Gas Pipeline Co New York 1,059 41 891 152 84 79 NH/RI/CT 329

Algonquin Gas Trans Co Rhode Island 560 5 296 4 53 -1 Rhode Island 145

Total 1,699 25 1,187 86 73 48

New Hampshire

Granite State Gas Trans Inc Maine 31 50 11 919 36 294 None c

Granite State Gas Trans Inc Massachusetts 31 19 10 -62 31 -68 Maine 31

Tennessee Gas Pipeline Co 75 10 45 82 61 65 None

Total 106 13 55 10 52 -2

Granite State Gas Trans Inc Vermont 31 29 22 -1 70 -24 None

Total 168 29 88 20 52 -7

New Jersey

Columbia Gas Trans Corp Delaware 141 -- 0 -- -- -- None

Columbia Gas Trans Corp Pennsylvania 245 47 219 216 89 114 None

Tennessee Gas Pipeline Co 499 3 263 27 53 24 New York 377

Texas Eastern Trans Corp 2,850 24 1,271 11 45 -10 New York 562

Transcontinental Gas P L Co 2,387 0 1,573 11 66 11 New York 885

Total 5,981 12 3,325 17 56 5

Total 6,122 15 3,325 17 56 6
Table A3. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Northeast Region, by State, 1990 and 1996 (Continued)

(Volumes in Million Cubic Feet per Day)

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 107

New York

Empire Pipeline Co Canada 503 -- 124 -- 25 -- None

Iroquois Pipeline Co 858 -- 782 -- 91 -- Connecticut 420

North Country P L Co 56 -- 44 -- 79 -- 

St Lawrence Gas 62 44 37 69 60 18 None

Tennessee Gas Pipeline Co 843 129 796 222 94 40 None

Total 2,322 466 1,783 563 77 17

Iroquois Pipeline Co Connecticut 250 -- 200 -- 80 -- New York 250

Algonquin Gas Trans Co New Jersey 1,150 13 629 8 55 -5 Connecticut 1,030

Tennessee Gas Pipeline Co 377 0 120 66 32 66 Connecticut 121

Texas Eastern Trans Corp 562 4 250 -4 45 -8 None

Transcontinental Gas P L Co 886 0 742 -9 84 -9 None

Total 2,975 5 1,741 1 59 -5

CNG Trans Corp Pennsylvania 1,565 8 446 26 29 -10 None c

Columbia Gas Trans Corp 131 33 73 -14 56 -35 Pennsylvania 1

National Fuel Gas Supply Co 116 0 97 160 83 160 Pennsylvania 321 c

Penn York Energy Corp 95 0 45 32 47 32 Pennsylvania 60 c

Tennessee Gas Pipeline Co 823 21 684 58 83 1 Massachusetts 1,059

Total 2,730 12 1,348 26 9 9

Total 8,277 46 5,072 65 61 12

Pennsylvania

Columbia Gas Trans Corp Maryland 206 41 0 -- -- -- Delaware/NY/NJ 547

Transcontinental Gas P L Co 2,050 0 1,748 -8 85 -8 Maryland/DE/NJ 2,463

Total 2,256 3 1,748 -11 85 -4

Transcontinental Gas P L Co New Jersey 1,900 9 0 -- -- -- None

Columbia Gas Trans Corp New York 1 0 0 -47 40 -47 None

National Fuel Gas Supply Co 321 23 234 -- 73 -- None c

Penn York Energy Corp 60 0 0 -- -- -- None c

Total 382 19 235 1,017 73 111

CNG Trans Corp Ohio 560 0 0 -- -- -- New York/MD 2,098

Tennessee Gas Pipeline Co 1,575 0 1,433 13 91 11 New York/NJ 1,322

Total 2,135 0 1,433 13 91 11

Carnegie Natural Gas Co West Virginia 30 0 20 100 84 23 None

CNG Trans Corp 500 0 507 316 67 100 Ohio 435

Columbia Gas Trans Corp 1,179 0 479 0 81 234 Ohio/MD/WV 651

Equitrans Inc 255 7 51 -19 49 21 West Virginia 70 c

Texas Eastern Trans Corp 2,625 4 2,400 20 91 16 New Jersey 2,850

Total 4,589 3 3,458 30 75 26

Total 11,262 4 7,241 -4 80 12

Rhode Island

Algonquin Gas Trans Co Connecticut 760 14 495 38 65 21 Massachusetts 705

Algonquin Gas Trans Co Massachusetts 145 9 72 -29 50 -35 None

Tennessee Gas Pipeline Co 173 518 146 597 85 13 None

Total 318 98 218 78 69 -10

Total 1,078 31 714 48 66 13

Vermont

Granite State Gas Trans Inc Canada 31 24 30 37 97 10 New Hampshire 31

Vermont Gas Sys Inc 40 25 21 17 53 -6 None

Total 71 25 51 28 72 3

Total 71 25 51 28 72 0
Table A3. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Northeast Region, by State, 1990 and 1996 (Continued)

(Volumes in Million Cubic Feet per Day)

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Energy Information Administration

108 Deliverability on the Interstate Natural Gas Pipeline System

Virginia

CNG Trans Corp Maryland 350 10 73 317 21 281 West Virginia 21

Transcontinental Gas P L Co North Carolina 2,587 7 2,033 -3 79 -9 Maryland/NC 2,520

East Tennessee Nat Gas Co Tennessee 26 102 0 -97 1 -98 None

Columbia Gas Trans Corp West Virginia 1,943 15 829 5 43 -8 Maryland/NC 1,137

Total 4,906 10 2,935 1 60 -8

West Virginia

Columbia Gas Trans Corp Kentucky 1,855 0 1,829 17 98 16 Virginia/PA 3,121

Tennessee Gas Pipeline Co 681 0 569 36 84 36 None

Total 2,536 0 2,398 21 95 21

Columbia Gas Trans Corp Maryland 5 0 0 -- -- -- 

Columbia Gas Trans Corp Ohio 12 0 0 -99 1 -96 None

Texas Eastern Trans Corp 2,740 12 2,421 21 88 8 Pennsylvania 2,625

Total 2,752 12 2,421 21 88 8

Columbia Gas Trans Corp Pennsylvania 579 0 0 -- -- -- OH/KY 938

Equitrans Inc 70 0 29 32 41 32 Pennsylvania 255

Total 649 0 29 -33 40 -33

CNG Trans Corp Virginia 21 -34 7 271 31 465 Ohio/PA 1,209

Total 5,962 5 4,855 20 90 27

Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. a

Average usage rate is equal to the average daily flow derived by estimated capacity. Utilization computation does not include capacity against b

which no flow was reported.

Bidirection flow occur on some or all of the pipeline company lines that cross the State border. The value shown represents the capacity, or c

sum of capacity, for only the flow in the direction indicated.

Less than 0.5 percent and greater than -0.5 percent. d

-- = Not applicable, pipeline not in service in 1990 and/or no flow reported in 1990 or 1996.

Note: Totals may not equal sum of components because of independent rounding.

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity

Database, as of December 1997.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 109

Figure A4. Major Interstate Natural Gas Pipelines in the Southeast Region

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, as of December 1997.
Table A4. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Southeast Region, by State, 1990 and 1996

(Volumes in Million Cubic Feet per Day)

Energy Information Administration

110 Deliverability on the Interstate Natural Gas Pipeline System

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Alabama

Koch Gateway Pipeline Co Florida 20 0 0 -- -- -- None c

Mobile Bay Pipeline Co Gulf of Mexico 600 -- 161 -- 27 -- None

Alabama-TN Nat Gas Co Mississippi 35 17 27 0 77 -14 None

Florida Gas Trans Co 1,375 70 900 18 65 -30 Florida 1,475

Koch Gateway Pipeline Co 300 -45 6 -97 2 -94 Florida 145 c

Southern Natural Gas Co 2,250 1,376 27 61 27 Georgia 1,530 d

Tennessee Gas Pipeline Co 1,899 20 1,818 55 96 30 Tennessee 1,732

Texas Eastern Trans Corp 2,108 0 2,010 22 96 21 Tennessee 2,151

Transcontinental Gas P L Co 3,302 0 2,694 -5 82 -5 Georgia 3,467

Total 11,269 6 8,839 14 78 8

Total 11,889 12 8,840 14 78 8

Florida

Florida Gas Trans Co Alabama 1,475 80 1,166 50 79 -17 None

Koch Gateway Pipeline Co 145 115 19 79 19 Alabama 20 d

Total 1,620 68 1,281 47 79 -13

South Georgia Nat Gas Co Georgia 56 30 38 92 69 48 None

Total 1,676 66 1,320 48 79 11

Georgia

South Georgia Nat Gas Co Alabama 132 39 103 54 78 11 Florida 56

Southern Natural Gas Co 1,530 0 1,034 21 68 21 South 332

Carolina/TN

Transcontinental Gas P L Co 3,467 7 2,969 5 86 -2 South Carolina 3,195

Total 5,129 5 4,106 9 80 4

Southern Natural Gas Co South Carolina 50 0 0 -- -- -- None

East Tennessee Nat Gas Co Tennessee 62 0 0 -- -- -- None

Total 5,241 5 4,106 9 78 83

Kentucky

ANR Pipeline Co Tennessee 1,398 7 1,291 31 92 23 Indiana 1,386

Columbia Gulf Trans Co 2,010 0 1,801 7 90 7 West Virginia 1,680

Midwestern Gas Trans Co 665 0 478 34 72 34 Indiana 663

Tennessee Gas Pipeline Co 2,671 10 2,531 15 95 5 Ohio/WV 2,458

Texas Eastern Trans Corp 2,104 0 2,015 22 96 22 Ohio 2,066

Texas Gas Trans Corp 1,669 0 1,519 32 91 32 Indiana/TN 1,534 c

Trunkline Gas Co 1,825 0 1,444 41 79 41 Illinois 1,799

Total 12,343 3 11,080 23 90 19

Columbia Gas Trans Corp West Virginia 76 0 0 -- -- -- Ohio/WV 2,254

Total 12,418 3 11,080 22 90 19

Mississippi

Koch Gateway Pipeline Co Alabama 200 33 0 -- -- -- None

ANR Pipeline Co Arkansas 1,430 6 1,213 21 85 15 Tennessee 1,480

Tennessee Gas Pipeline Co 1,580 1 900 -15 57 -16 Tennessee 2,132

Texas Gas Trans Corp 2,163 0 1,647 21 76 21 Tennessee 1,880

Trunkline Gas Co 1,853 0 1,356 24 73 24 Tennessee 1,836

Total 7,026 1 5,116 13 73 12

Chandeleur Pipeline Co Gulf of Mexico 275 0 85 -43 31 -43

Columbia Gulf Trans Co Louisiana 1,982 -7 1,756 1 89 8 Tennessee 1,961

Florida Gas Trans Co 1,300 58 870 20 67 -24 Alabama 1,375

Koch Gateway Pipeline Co 1,030 8 474 -34 46 -39 Alabama/LA 610 c

Mid-Louisiana Gas Co 70 0 60 0 86 0 Louisiana 70
Table A4. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Southeast Region, by State, 1990 and 1996 (Continued)

(Volumes in Million Cubic Feet per Day)

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 111

Southern Natural Gas Co 1,661 0 1,319 20 79 20 Alabama 2,250

Tennessee Gas Pipeline Co 2,520 5 1,975 4 78 0 Alabama 1,899

Texas Eastern Trans Corp 2,202 25 1,965 40 89 12 Alabama 2,108

Transcontinental Gas P L Co 3,056 0 2,528 3 83 3 Alabama 3,302

Total 13,821 7 10,947 8 79 1

Total 21,321 5 16,148 9 77 4

North Carolina

Transcontinental Gas P L Co South Carolina 3,002 8 2,638 4 88 -4 Virginia 2,587

Columbia Gas Trans Corp Virginia 25 0 15 14 60 14 None

Transcontinental Gas P L Co 420 -- 0 -- -- -- None

Total 445 1,680 15 14 60 14

Total 3,447 23 2,653 4 88 -4

South Carolina

Southern Natural Gas Co Georgia 276 0 216 8 78 8 Georgia 50

Transcontinental Gas P L Co 3,195 7 2,797 5 88 -2 North Carolina 3,002

Total 3,471 7 3,013 6 87 7

Tennessee

Tennessee Gas Pipeline Co Alabama 1,732 16 1,678 53 97 33 Kentucky 2,671

Texas Eastern Trans Corp 2,151 0 2,010 21 93 21 Kentucky 2,104

Total 3,883 6 3,688 34 95 25

Southern Natural Gas Co Georgia 56 25 22 0 39 -20 None

Texas Gas Trans Corp Kentucky 25 -- 0 -- -- -- None c

Alabama-TN Nat Gas Co Mississippi 91 1,031 7 0 8 -91 None

ANR Pipeline Co 1,418 7 1,205 21 85 14 Kentucky 1,398

Columbia Gulf Trans Co 1,961 -5 1,731 1 88 6 Kentucky 2,010

Noram Gas Transmission Co 25 0 0 -- -- -- Arkansas 25

Tennessee Gas Pipeline Co 2,132 1 1,896 32 89 30 None

Texas Gas Trans Corp 1,880 0 1,579 23 84 23 Kentucky 1,669

Trunkline Gas Co 1,836 0 1,346 24 73 24 Kentucky 1,825

Total 9,342 1 7,764 19 83 18

Total 13,306 3 11,475 23 87 20

Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. a

Average usage rate is equal to the average daily flow derived by estimated capacity. Utilization computation does not include capacity against b

which no flow was reported.

Bidirection flow occur on some or all of the pipeline company lines that cross the State border. The value shown represents the capacity, or c

sum of capacity, for only the flow in the direction indicated.

Less than 0.5 percent and greater than -0.5 percent. d

-- = Not applicable, pipeline not in service in 1990 and/or no flow reported in 1990 or 1996.

Note: Totals may not equal sum of components because of independent rounding.

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity

Database, as of December 1997.
Energy Information Administration

112 Deliverability on the Interstate Natural Gas Pipeline System

Figure A5. Major Interstate Natural Gas Pipelines Exporting from the Southwest Region

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, as of December 1997.
Table A5. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Southwest Region, by State, 1990 and 1996

(Volumes in Million Cubic Feet per Day)

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 113

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Average Usage Rate Exiting Capacity a b

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Arkansas

ANR Pipeline Co Louisiana 1,430 7 1,213 21 85 14 Mississippi 1,430

Mississippi River Trans Corp 730 35 111 -57 15 -68 Missouri/LA 1,280 c

Noram Gas Transmission Co 120 0 44 -- 37 -- Missouri 100 c

Tennessee Gas Pipeline Co 1,581 0 901 -14 57 -14 Mississippi 1,580

Texas Gas Trans Corp 2,002 0 1,592 24 80 24 Mississippi 2,163

Trunkline Gas Co 1,853 0 1,356 24 73 24 Mississippi 1,852

Total 7,716 4 5,218 11 68 6

Associated Natural Gas Co Missouri 30 0 26 250 88 250 Missouri 10 c

Noram Gas Transmission Co Oklahoma 1,654 1,010 47 61 47 Louisiana/TX 206 d

Ozark Gas Trans Sys 170 0 81 353 48 353 None

Total 1,824 0 1,091 55 60 55

Noram Gas Transmission Co Tennessee 25 0 0 -- -- -- None

Natural Gas P L Co of America Texas 1,893 19 1,167 32 62 11 Missouri 2,250 c

Texas Eastern Trans Corp 267 5 179 257 67 241 Missouri 300

Total 2,160 17 1,345 44 62 23

Total 11,755 5 7,680 21 65 13

Louisiana

Mississippi River Trans Corp Arkansas 550 0 539 10 98 10 None c

Noram Gas Transmission Co 156 -31 0 -- -- -- Texas 25

Total 706 -9 539 10 98 10

ANR Pipeline Co Gulf of Mexico 1,919 NA NA -- NA -- -- d

Columbia Gulf Trans Co 1,210 NA NA -- NA -- --

High Island Offshore Co 1,800 NA NA -- NA -- --

Koch 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 -- --

1,700 NA NA -- NA -- --

1,226 NA NA -- NA -- --

Total 17,627 NA NA -- NA -- --

Koch Gateway Pipeline Co Mississippi 310 0 0 -- -- -- None c

Mid-Louisiana Gas Co 70 0 60 -- 86 -- None

Total 380 0 60 -- 16 --

Florida Gas Trans Co Texas 320 7 253 23 79 16 Mississippi 1,340

Gulf States Transmission Corp 75 0 9 17 13 17 None

Koch Gateway Pipeline Co 825 731 39 89 40 Mississippi 1,030 d

Mississippi River Trans Corp 85 0 58 97 68 97 Arkansas 1,340

Natural Gas P L Co of America 725 0 663 357 91 357 None c

Noram Gas Transmission Co 140 87 93 44 67 -23 Arkansas 825

Sabine Pipe Line Company 270 0 98 -- 36 -- None

Southern Natural Gas Co 110 18 48 81 44 54 Mississippi 1,661

Tennessee Gas Pipeline Co 1,307 13 1,231 23 94 9 Mississippi/AR 4,101

Texas Eastern Trans Corp 743 10 602 -1 81 -9 Mississippi 2,201 c

Texas Gas Trans Corp 179 30 161 38 90 6 Arkansas 2,002

Transcontinental Gas P L Co 725 0 702 12 97 12 Mississippi 3,056

Trunkline Gas Co 334 0 307 21 92 21 Arkansas 1,852

Total 5,838 6 4,958 38 85 23

ANR Pipeline Co Louisiana -- -- -- -- -- Arkansas 1,338 e

Columbia Gulf Transmission Co -- -- -- -- -- Mississippi 2,133 e

Natural Gas PL Co of America -- -- -- -- -- Texas 509 e

Transwestern Pipeline Corp -- -- -- -- -- Texas 199 e

Total 24,560 4 8,093 50 78 11
Table A5. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Southwest Region, by State, 1990 and 1996 (Continued)

(Volumes in Million Cubic Feet per Day)

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Average Usage Rate Exiting Capacity a b

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Energy Information Administration

114 Deliverability on the Interstate Natural Gas Pipeline System

New Mexico

El Paso Natural Gas Co Colorado 650 50 573 47 88 -2 Arizona 650

Transcolorado Gas Trans Co 120 -- 100 -- 83 -- None

Transwestern Pipeline Co 500 233 277 -- 55 -- Arizona 500

Total 1,270 118 949 143 75 17

El Paso Natural Gas Co Texas 2,750 7 7 -99 0 -99 Arizona 4,261 c

Natural Gas P L Co of America 550 91 4 -95 1 -97 Texas 720 c

Transwestern Pipeline Co 950 21 0 -- -- -- Arizona 1,090 c

Total 4,250 17 11 -99 1 -98

Total 5,520 30 960 -53 52 4

Oklahoma

Colorado Interstate Gas Colorado 250 25 201 37 80 10 Texas 200 c

KN Interstate Gas Co Kansas 5 0 4 -- 80 -- Texas 35

Natural Gas P L Co of America 300 0 0 -- -- -- Texas 750 c

Williams Natural Gas Co 259 48 87 212 34 111 Missouri 496

Total 564 18 91 227 36 117

ANR Pipeline Co Texas 580 21 319 457 55 362 Kansas 853

Colorado Interstate Gas 200 0 100 -- 50 -- None c

El Paso Natural Gas Co 152 0 51 -- 33 -- None c

KN Interstate Gas Co 135 0 70 -- 52 -- None c

Natural Gas P L Co of America 1,765 16 617 52 35 22 Kansas/TX 1,903 c

Northern Natural Gas Co 2,500 0 451 74 18 25 Kansas 1,330 c

Panhandle Eastern P L Co 389 -4 289 82 74 89 Kansas/TX 1,451 c

Transok Inc 30 -- 24 -- 80 -- None

Transwestern Pipeline Co 75 0 40 -36 53 -36 Kansas 5

Williams Natural Gas Co 100 0 66 -3 66 -3 Kansas 496

Total 5,926 6 2,027 100 34 45

Total 6,740 8 2,318 95 36 41

Texas

Natural Gas P L Co of America Arkansas 600 0 0 0 -- -- None c

Noram Gas Transmission Co 50 43 12 -55 23 -68 Louisiana 140

Total 650 2 12 -55 23 -68

Black Marlin Pipeline Co Gulf of Mexico 384 NA NA -- NA -- -- d

Natural Gas PL Co of America 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 -- --

Transcontinental Gas PL Co 400 NA NA -- NA -- --

Total 1,530

Koch Gateway Pipeline Co Louisiana 20 0 4 -- 19 -- None

Natural Gas P L Co of America 140 -90 0 -- -- -- Arkansas 1,873 c

Noram Gas Transmission Co 25 0 14 138 58 138 None

Texas Eastern Trans Corp 199 0 0 -- -- -- Louisiana 743 c

Total 384 -77 18 -43 41 45

Texas Eastern Trans Corp Mexico 350 0 37 -- 11 -- None c

El Paso Natural Gas Co New Mexico 1,546 0 601 -- 39 -- None c

Natural Gas P L Co of America 720 41 282 56 39 81 Oklahoma 1,765 c

Northern Natural Gas Co 200 0 141 23 70 23 Oklahoma 2,500 c

Transwestern Pipeline Co 800 2 523 62 65 40 Oklahoma 75 c

Total 3,266 7 1,548 43 47 78

ANR Pipeline Co Oklahoma 150 0 119 332 79 332 None

Colorado Interstate Gas 200 0 24 -56 12 -56 None c

El Paso Natural Gas Co 250 0 12 -95 5 -95 New Mexico 2,750 c

KN Interstate Gas Co 35 0 3 -81 8 -81 None c

Natural Gas P L Co of America 750 22 572 18 76 -4 New Mexico 550 c
Table A5. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Southwest Region, by State, 1990 and 1996 (Continued)

(Volumes in Million Cubic Feet per Day)

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Average Usage Rate Exiting Capacity a b

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 115

Noram Gas Transmission Co 139 0 13 141 9 141 None

Northern Natural Gas Co 1,050 75 175 41 17 -19 None c

Panhandle Eastern P L Co 56 0 34 7 60 7 Oklahoma 389 c

Transok Inc 50 -- 11 -- 22 -- None

Transwestern Pipeline Co 115 35 26 -58 23 -69 New Mexico 950

Total 2,795 31 988 -5 38 -22

Total 8,575 -4 2,759 95 41 73

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

Transcontinental 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 e

Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. a

Average usage rate is equal to the average daily flow derived by estimated capacity. Utilization computation does not include capacity against b

which no flow was reported.

Bidirection flow occur on some or all of the pipeline company lines that cross the State border. The value shown represents the capacity, or c

sum of capacity, for only the flow in the direction indicated.

List of Offshore-to-Onshore capacity levels is not all inclusive. In some cases capacity levels may be understated. d

The pipeline, or a portion of the pipeline system, begins service in the “Receiving State.” Pipeline is shown here for purposes of showing e

capacity exiting the State.

-- = Not applicable, pipeline not in service in 1990 and/or no flow reported in 1990 or 1996. NA = Not available.

Note: Totals may not equal sum of components because of independent rounding.

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity

Database, as of December 1997.
San Diego Gas & Electric Co

(Intrastate)

Northwest Pipeline Co

Southern California Gas Co

(Intrastate)

Tuscarora Gas Transmission Co

= Underground Storage

 Pacific Gas & Electric Gas

 Gas Transmission Co (Intrastate) Paiute Pipeline Co 

Southwest Gas Co

(Intrastate)

Mojave Pipeline Co

Transwestern Gas Pipeline Co

El Paso Natural Gas Co

Kern River Gas Transmission Co

Pacific Gas & Electric Gas Transmission Co

- Northwest

Energy Information Administration

116 Deliverability on the Interstate Natural Gas Pipeline System

Figure A6. Major Interstate Natural Gas Pipelines Serving the Western Region

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, as of December 1997.
Table A6. State Border Capacity, Flows, and Utilization Rates of Interstate Natural Gas Pipelines

Operating in the Western Region, by State, 1990 and 1996

(Volumes in Million Cubic Feet per Day)

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 117

Transmission Throughput Capabilities and Flows

Estimated Entering Capacity Average Daily Flow Exiting Capacity a Average Usage

Rateb

Receiving State/ Upstream Change Change Change Downstream

 Via Pipeline Company State 1996 1990-1996 1996 1990-1996 1996 1990-1996 State 1996

Percent Percent Percent

Arizona

El Paso Nat Gas Co New Mexico 4,261 19 2,285 -29 54 -41 California/NV/MX 3,679

Transwestern Pipeline Co 1,090 41 130 -81 12 -87 California 1,225

Total 5,351 23 2,415 -38 45 -50

California

El Paso Nat Gas Co Arizona 3,443 21 1,607 -40 47 -50 None

Mojave Pipeline Co 450 -- 295 -- 66 -- None

Transwestern Pipeline Co 1,225 61 430 -38 35 -61 None

Total 5,118 42 2,332 -31 46 -51

Pacific Interstate Offshore Co Offshore Calif. 60 0 14 -53 23 -53 None

Kern River Gas Trans Co Nevada 750 -- 658 -- 89 -- None

Paiute Pipeline Co 30 39 8 -49 27 -63 None

Total 780 3,530 666 -49 85 14

Pacific Gas Transmission Co Oregon 1,950 62 1,594 54 82 -10 None

Tuscarora Pipeline Co 113 -- 53 -24 48 -- Nevada 95

Total 2,063 72 1,647 49 80 -18

Total 7,961 65 4,646 -3 59 -37

Idaho

Pacific Gas Transmission Co Canada 2,660 55 2,301 63 87 -2 Washington 2,632

Northwest Pipeline Corp Oregon 481 9 344 1,250 72 1,138 Nevada 158 c

Northwest Pipeline Corp Utah 444 22 0 -100 -- -- Utah 298 c

Northwest Pipeline Corp Washington 122 0 0 0 -- -- None

Total 3,707 39 2,645 62 90 5

Nevada

El Paso Nat Gas Co Arizona 191 14 109 27 57 11 None

Tuscarora Pipeline Co California 95 -- 53 -12 56 -- None

Northwest Pipeline Corp Idaho 158 32 132 28 84 -3 None

Kern River Gas Trans Co Utah 750 -- 712 -- 95 -- California 750

Total 1,194 310 1,006 304 84 -3

Oregon

Northwest Pipeline Corp Idaho 254 6 0 -- -- -- Washington 941 c

Northwest Pipeline Corp Washington 739 77 228 277 31 113 Idaho 481 c

Pacific Gas Transmission Co 2,378 57 2,095 60 88 -3 California 2,063

Total 3,117 61 2,323 69 75 3

Total 3,371 55 2,323 69 75 3

Washington

Ferndale P L Co Canada 45 -- 2 -- 4 -- None

Northwest Pipeline Corp 1,066 29 969 110 91 62 Oregon 1,289

Sumas International Pl Co 15 0 4 40 28 40 None

Total 1,126 34 975 110 87 57

Pacific Gas Transmission Co Idaho 2,632 66 2,251 62 86 -10 Oregon 2,378

Northwest Pipeline Corp Oregon 941 24 0 -- --- -- Idaho 122 c

Total 4,699 47 3,226 70 91 20

Average daily flow based upon annual volumes (reported as delivered from one State to another) divided by days in the year. a

Average usage rate is equal to the average daily flow derived by estimated capacity. Utilization computation does not include capacity against b

which no flow was reported.

Bidirection flow occur on some or all of the pipeline company lines that cross the State border. The value shown represents the capacity, or c

sum of capacity, for only the flow in the direction indicated.

-- = Not applicable, pipeline not in service in 1990 and/or no flow reported in 1990 or 1996.

Note: Totals may not equal sum of components because of independent rounding.

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline State Border Capacity

Database, as of December 1997.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 119

Appendix B

Natural Gas Pipeline and System Expansions, 1997-2000

A great deal of new pipeline capability has been proposed for

development throughout North America between now and the

turn of the century. The most extensive development is

focused 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 access to natural gas supplies in

Western Canada but also to production from the developing

areas, such as the Sable Island field in Eastern Canada. The

second-largest focus is on improving access to the increasing

deep-water production in the Gulf of Mexico. Next are those

projects whose objectives are to increase the flow of lowercost supplies located in the Central United States to markets

located primarily in the Midwest. Currently, the capability to

do so is limited in some areas. The latter series of expansions

will be competing, to some degree, with the projects slated to

increase flows of Western Canadian gas to the Midwest

marketplace.

Although there is a question as to whether or not the market

can support all these expansions, it must be kept in mind that

these projects can proceed only if sufficient commitments are

entered into by future customers. Most of the proposed 120

projects have, or are, undergoing market-testing through

“open-season” offerings whereby potential customers have

placed bids for future capacity on the proposed projects. The

planned capacity of the proposed projects usually reflects the

results of these open seasons and indicates that, at least at the

moment, local distribution companies and other major

customers believe demand will grow sufficiently to support

the incremental supplies destined for these markets.

This appendix examines expansions to the North American

natural gas pipeline network during 1997 and the nature and

type of proposed pipeline projects announced or approved for

construction during the next several years in the United

States. It includes those projects in Canada and Mexico that

tie in with U.S. markets or projects. Additional details on

some of the proposed projects and an analysis of their

potential impact on a regional basis or on the overall North

American natural gas pipeline network may be found in the

main body of the report.

Overview

At least 41 pipeline expansion projects were completed and

placed in service in the United States during 1997 (Figure B1)

representing more than 6.3 billion cubic feet per day (Bcf/d)

of added pipeline capacity. These projects either added

capacity directly to the interstate network, improved local

intrastate service, or expanded access to producing fields or

natural gas market centers. Seven of the projects increased

interregional transmission capability by 750 million cubic feet

per day (MMcf/d): 513 MMcf/d in the United States and

237 MMcf/d into Mexico (Tables ES1 and B1). These

projects, plus others, increased overall daily interstate

capability by a little more than 2 percent, or 4.6 Bcf, which is

double the interstate capacity added in 1996. Moreover, the 121

total number of completed projects in the United States was

substantially more than in 1995 (41 vs. 26).

Almost all the natural gas pipeline projects slated for

completion in 1997 were placed in service on schedule.122

Two were canceled because of changes in market conditions

or competitive pressures. A few others were postponed while

their original designs were reevaluated in light of conditional

regulatory approval or shifts in construction priorities.

As of February 1998, the Energy Information Administration

was tracking more than 100 proposed pipeline expansions and

new pipeline projects at various stages of development in the

United States, Canada, and Mexico, with planned in-service

dates between 1998 and the end of 2000 (Figure B2). A

number of these projects are slated to be phased in over

several years or are jurisdictionally segmented (for instance,

U.S. versus Canadian segments). If all U.S. projects were

completed, overall daily deliverability on the national

network would increase by almost 30 billion cubic feet

(3 gathering system projects in the Gulf of Mexico and

11 Canadian projects, some of which are counted in the U.S.

projects, are not included). Of all phases/projects, 62 are

proposed for completion in 1998, 38 in 1999, and 20 in 2000.

Thirty-nine of the projects call for development of new

pipeline systems or facilities at new international border

points (Table B2).

Without firm customer commitments, neither the necessary regulatory Energy Information Administration, “Natural Gas Pipeline and System 120

approval nor any needed external financing will be forthcoming. Nevertheless, Expansions,” Natural Gas Monthly,” DOE/EIA-0130(97/04) Washington, DC,

it is possible that some customers might back out of these commitments after April 1997).

initial regulatory approval, thereby leaving the final implementation of a Energy Information Administration, “Natural Gas Pipeline and System

project in doubt. Expansions,” Natural Gas Monthly (April 1997), Table SR2.

121

122
AB

VT

Southeast

Northeast

Midwest

Southwest

Western

Central

Mexico

Canada

ON

PA

MB

CT

DE

MD DC

NJ

RI

MA

NY NH

NC

VA

SK BC

QU

NK

MI

LA

WY

KY

GA

MT

ID

MN

NE

TX

26

18

21

16

12

AL

AR

AZ

CA

CO

FL

IA

IL IN

KS

ME

MO

MS

ND

NM

NV

OH

OK

OR

SC

SD

TN

UT

WA

WI

MX

1

2

4 3

5

6

7

8

9

11 10

13 14

15

17

19

20

22

23

24

25

27

28

29

30

31

32

33

34 35

36

37

38

39

40

41

42

43

44

45

46

Energy Information Administration

120 Deliverability on the Interstate Natural Gas Pipeline System

Figure B1. General Location of Major Natural Gas Pipeline Construction Projects Completed in 1997

(Keyed to Table B1)

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline Construction Database,

as of March 1998.

Recent Developments and

 Proposals

The least amount of interstate pipeline development in 1997

occurred in the Western Region with the completion of only

one small project (13 MMcf/d) serving the Reno area of

Nevada and California. In addition, the Western Region has 123

the least amount of proposed new pipeline capacity

development of the regions. This is not surprising since the

region currently has an excess of interstate capacity. Between

1990 and the end of 1996, interstate capacity into the region

increased by 45 percent, from 7.1 to 10.3 Bcf/d, more than for

any other region (see Chapter 4).

Other regions of North America saw more extensive pipeline

development in 1997 or are slated for significant expansions

in the next several years. These expansions can be looked at

in two ways. First are those projects that are designed to

improve access to developing production areas which have

become capacity constrained. On the opposite side of the coin

are the pipeline expansions that are designed to improve

transportation to expanding market areas and which may or

may not be tied in with accessing developing production

sources. The following sections look first at projects and

trends that are production-area focused and then at those that

are geared toward specific markets.

Production Areas 

Gulf of Mexico

One of the more significant events of the past several years

has been the increased attention to development of gas

One other project was completed within the Western Region in 1997, 123

the El Paso Havasu Crossover expansion. However, the purpose of this

expansion was to increase the capability of the El Paso system to deliver

additional supplies to West Texas, not for service within the Western Region

itself. 
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 121

Table B1. Major Natural Gas Pipeline Construction Projects Completed in 1997, by Terminating Region

Year State State Region Key Pipeline/Project Name Number Date Expansion Miles (million $) (MMcf/d)

Ends FERC In New Cost Added

in Begins in Map Docket Service or Estimate Capacity

Canada

1997 QU SK Canada 1 TransCanada System Expn -- 11-1-97 Expn 128 NA 119

1997 NY QU Canada 2 TransCanada Import (Iroquois NY) -- 11-1-97 Expn NA NA 24

1997 NY QU Canada 3 TransCanada Import (Chippawa NY) -- 11-1-97 Expn NA NA 48

1997 NY QU Canada 4 TransCanada Import (Niagara NY) -- 11-1-97 Expn NA NA 39

1997 MN SK Canada 5 TransCanada Import (Noyes MN) -- 11-1-97 Expn NA NA 56

Central

1997 WY WY Central 6 CIG Wind River Lateral Expn CP96-289 11-1-97 Expn NA 11 40

1997 ND SK Canada 7 ISP “Solution Gas” Imports CP96-684 11-1-97 New 1 1 3

1997 MO WY Central 8 KN Interstate Pony Express CP96-477 8-1-97 New 850 154 255

1997 WY WY Central 9 MIGC HiLight Plant Expn CP97-183 10-1-97 Expn NA 6 45

1997 NE CO Central 10 Trailblazer Eastward Expn CP96-506 11-1-97 Expn 445 NA 105

1997 KS WY Central 11 Williams Gas WY-KS Expn CP97-7 12-15-97 Expn NA 9 30

1997 MO KS Central 12 Williams Gas KS-MO Expn CP97-776 11-1-97 Expn 13 6 21

1997 CO WY Central 13 Wyoming Interstate Eastward CP96-288 8-1-97 Expn NA 40 192

Midwest

1997 MI IL Midwest 14 ANR Michigan Leg Expn CP96-641 12-1-97 Expn 12 19 135

1997 WI KS Central 15 Northern Natural Peak Day 2000 I CP97-25 11-1-97 Expn 39 102 244

1997 WI MB Canada 16 Viking System-Wide Expn CP97-93 11-1-97 Expn 30 28 62

Northeast

1997 CT CT Northeast 17 Algonquin Electric Load Lateral CP96-201 11-1-97 Expn 8 15 82

1997 PA WV Northeast 18 CNG Seasonal Service Expn CP96-492 12-15-97 Expn NA 1 30

1997 VA PA Northeast 19 CNG PL-1 Phase I CP96-492 11-1-97 Expn NA 15 19

1997 VA VA Northeast 20 Columbia/Commonwealth PL Expn NA 11-1-97 Expn NA NA 18

1997 VA PA Northeast 21 Columbia Gas Market Expn I CP96-213 11-1-97 Expn 379 22 242

1997 VA TN Southeast 22 East Tennessee System Wide CP96-696 11-1-97 Expn 6 13 24

1997 MD DE Northeast 23 Eastern Shore Bridgeville Expn CP96-97 11-1-97 Expn 29 7 5

1997 PA NY Northeast 24 National Fuel Niagara Expn CP96-545 11-1-97 Expn 139 6 25

1997 PA PA Northeast 25 Texas Eastern Virginia Natural Expn CP96-606 11-1-97 Expn NA NA 20

1997 PA PA Northeast 26 Texas Eastern Columbia Expn CP96-559 11-1-97 Expn 81 67 142

1997 PA PA Northeast 27 Texas Eastern Line 1-A Expn CP97-276 12-31-97 Expn 23 13 128

1997 PA PA Northeast 28 Transco Pocono Project CP97-328 11-1-97 Expn 5 10 37

Southeast

1997 AL AL Southeast 29 MidCoast Pipeline System Expn CP97-343 11-1-97 Expn NA 2 8

1997 SC GA Southeast 30 SONAT Zone 3 GA-SC-TN CP96-541 11-1-97 Expn 27 36 45

1997 SC SC Southeast 31 South Carolina Pipeline Expn -- 11-1-97 Expn NA 10 200

1997 NC NC Southeast 32 Transco Maiden Lateral Expn CP97-193 12-1-97 Expn 18 13 38

1997 SC MS Southeast 33 Transco Sunbelt Project NA 11-1-97 Expn 570 85 145

Southwest

1997 GM GM Offshore 34 DIGS Main Pass Gathering CP97-300 12-20-97 New 63 54 200

1997 TX TX Southwest 35 Delhi Pipeline South Texas Expn -- 11-1-97 Expn 53 NA 90

1997 LA GM Offshore 36 Discovery Pipeline CP96-712 11-1-97 New 147 189 600

1997 TX AZ Western 37 El Paso Havasu Crossover CP96-321 11-1-97 Expn 98 20 180

1997 GM GM Offshore 38 Garden Banks Offshore System CP96-113 11-1-97 New 50 NA 600

1997 LA GM Offshore 39 Koch Bastian Bay CP96-572 11-1-97 Expn 16 NA 861

1997 GM GM Offshore 40 Manta Ray Gathering System CP96-796 11-1-97 New 47 60 300

1997 LA GM Offshore 41 Nautilus System CP96-790 11-1-97 New 87 121 600

1997 OK OK Southwest 42 Transok West-to-East System Expn -- 11-1-97 Expn 130 75 255

1997 NM NM Southwest 43 Transwestern Bloomfield Expn CP97-286 12-1-97 Expn -- NA 25

Western

1997 CA NV Western 44 Paiute Pipeline North Taho Lateral CP94-29 12-15-97 New 23 10 13

Mexico

1997 MX CA Western 45 SoCal Calexico/Mexicali Export NA 7-31-97 New 1 25 a

1997 MX TX Southwest 46 El Paso Samalayucca II CP93-252 12-20-97 New 21 15 212

Less than $1 million. All cost estimates are in U.S. dollars. a

MMcf/d = Million cubic feet per day. Expn = Expansion. NA = Not available. -- = Not applicable.

CIG = Colorado Interstate Gas Co.; CNG = CNG Transmission Co; DIGS = Dauphin Island Gathering System; GM = Gulf of Mexico; NGPL =

Natural Gas Pipeline Co. of America; NSPC = Northern States Power Co.; SoCal = Southern California Gas Co.; SONAT = Southern Natural Gas

Co.; Tenneco = Tennessee Gas Pipeline Co.; TCPL = TransCanada Pipeline Ltd.; Transco = Transcontinental Gas Pipeline Co.

Note: Bold underlined items indicate project crosses regional boundary.

Source: Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Proposed Pipeline Construction Database,

as of March 1998, compiled from Federal Energy Regulatory Commission filings and various industry news sources.
AB

VT

Southeast

Northeast

Midwest

Southwest

Western

Central

Mexico

Canada

NJ

NK

WV

VA

NC

DCMD

CO

OH PA

IN

KY

NY

QU

MA

NH

CT

RI

MI ON

DE

AL LA

TN

GA

WI MN

MB

UT

ID

MS

KS

SK

ME

MO

ND

TX

BC

WY

MT

NE

D11

D16

F3 F12 E11

F11

D26

C12

F10

E2

E5

C11 C17

C20

A6 A3

G6

G2

G1

A5

AR

AZ

CA

FL

IA

IL

NM

NV

OK

OR

SC

SD

WA

A1 A2

A4

A7

A8

A9

A10

A11

B1

B2 B3

B4

B5 B6

B7

B8

B9

B10

B11

B12

B13

B14

C1

C2

C3 C4 C5

C6

C7

C8 C9

C10

C13

C14

C15

C16

C18

C19

D1

D2

D3

D4

D5

D6

D7

D8

D9

D10

D12

D13

D14 D15

D17

D18

D19

D20

D21

D22

D23

D24

D25

D27

D28

E1

E3

E4

E6

E7

E8

E9

E10 E12

E13

E14

E15

F1

F2

F4

F5

F6

F7

F8

F9

F13

F14

F15F16

G3

G4

G5

G7

H1

H2

H3

H4

H5

Energy Information Administration

122 Deliverability on the Interstate Natural Gas Pipeline System

Figure B2. General Location of Major Proposed Natural Gas Pipeline Construction Projects, 1998-2000

(Keyed to Table B2)

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline Construction Database,

as of March 1998.

resources in the Gulf of Mexico and, specifically, 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 Mississippi Canyon areas. Companies such as Shell Oil,

projects were completed in the Gulf, representing a total of Transcontinental Pipeline, and Williams Natural Gas

3.2 Bcf/d of new pipeline capacity (Table B1). Three of these Transmission are involved (Table B2). Development of

projects now bring an additional 2.1 Bcf/d to onshore offshore and deep water pipeline-related projects represents

Louisiana, while the other three (1.1 Bcf/d) operate as 52 percent of the 3.7 Bcf/d of planned additions in the

gathering systems linking producing platforms in the Gulf Southwest Region and 44 percent of the 4.0 Bcf/d in the

with mainlines directed to onshore facilities. The largest of Southeast Region.

the new systems include the Nautilus and Texaco Discovery

pipelines, both with capacities of 0.6 Bcf/d. The remaining proposed onshore expansion projects in the

At least 10 offshore projects, representing more than to supplies in the east and south Texas and in the San Juan

3.7 Bcf/d of capacity, have been proposed for development in Basin of New Mexico. Several proposed projects in south

1998/1999. Most of these projects would reach into the deep Texas are designed to support exports to Mexico, if and when

water area of the Gulf to tap several new production sources the connecting export facilities are finally put in place.

124

Southwest Region are designed primarily to increase access

Three projects would direct supply to the Southeast (Alabama and 124

Mississippi) and three to the Southwest (Louisiana). The other projects would

be gathering systems.
Table B2. Major Proposed Natural Gas Pipeline Construction Projects, by Terminating Region and

Planned In-Service Year, 1998–2000

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 123

Year State State Region Key Pipeline/Project Name Number 3-31-98 Expansion Miles (million $) (MMcf/d)

Ends FERC Status New Cost Added

in Begins in Map Docket As of or Estimate Capacity a

Canada

1998 SK AB Canada A1 Alberta Energy/TransCanada Expn -- Approved Expn 71 18 200

1998 SK SK Canada A2 Foothills Pipeline Eastern Expn -- Approved New 70 18 700

1998 QU SK Canada A3 TransCanada 1998 System Expn -- Pending Expn 235 840 447

1999 NB NS Canada A4 Maritimes & Northeast Phase II -- Pending New 386 434 465

1999 AB AB Canada A5 NOVA System Expn -- Pending Expn 125 1,070 2,250

1999 QU SK Canada A6 TransCanada System 1999 Expn -- Pending Expn NA NA NA

1999 MB AB Canada A7 TransCanada Voyageur Link -- Announced Expn NA NA 1,400

1999 ON MI Midwest A8 Vector Pipeline (Canada Portion) -- Pending New 15 24 1,000

2000 SK BC Canada A9 Alliance Pipeline (Canada Portion) -- Pending New 982 700 1,325

2000 BC BC Canada A10 ANG Kootenay Pacific Pipeline -- Pending New 351 381 550

2000 ON MI Midwest A11 TriStatePipeline (Canada Portion) -- Announced Expn NA NA 300

Total New Capacity 8,637

Central

1998 CO CO Central B1 CIG Campo Lateral CP97-769 Approved Expn 115 21 81

1998 CO CO Central B2 PSCO Front Range -- Pending Expn 53 25 269

1998 WY CO Central B3 KN Interstate Front Runner CP97-707 Pending New 109 NA 254

1998 NE OK Southwest B4 NGPL Amarillo Upgrade CP94-577 Approved Expn 14 33 -25

1998 WY WY Central B5 MIGC Southern Mainline Expn CP98-125 Pending Expn NA 6 40

1998 IA IA Central B6 Northern Border Harper Expn CP95-194 Approved Expn 142 NA 962

1998 IA SK Canada B7 Northern Border Monchy Expn CP95-194 Approved Expn 243 797 700

1998 WY UT Central B8 Questar Utah Mainline Expn CP98-66 Approved Expn NA 8 90

1998 UT WY Central B9 Questar Mainline (Line 58) Expn CP96-820 Approved Expn 41 18 55

1998 CO CO Central B10 TransColorado Pipeline (Northern) CP90-1777 Approved New 266 184 300

1998 WY WY Central B11 WIG Larimie Compressor Expn CP98-128 Pending Expn NA 15 52

1998 MO MO Central B12 Williams Natural Gas St Louis Expn -- Announced Expn 200 NA 52

2000 ND SK Canada B13 Alliance Pipeline (Import Station) CP97-169 Approved New 1 139 1,600

2000 WY SK Canada B14 Altamont Pipeline CP90-1372 Approved New 620 139 737

Total New Capacity 5,143

Midwest

1998 MI MI Midwest C1 Great Lakes Security Looping II CP96-297 Approved Expn 25 44 0

1998 MI MB Canada C2 Great Lakes System Wide Expn CP96-647 Approved Expn 72 149 129

1998 IL IA Central C3 NGPL Amarillo Expn CP96-27 Approved Expn 4 24 110

1998 IL IA Central C4 Northern Border Manhattan Extn CP95-194 Approved New 200 NA 648

1998 WI KS Central C5 Northern Natural Peak Day 2000 II CP97-25 Approved Expn 5 NA 32

1998 MN MN Midwest C6 Northern Natural Line D Expn CP98-132 Approved Expn 10 9 40

1998 OH IN Midwest C7 Texas Eastern Spectrum Expn CP97-626 On hold Expn 114 31 305

1999 WI IL Midwest C8 ANR IL-WI Expn CP97-765 Approved Expn 11 24 116

1999 OH IL Midwest C9 ANR Independence Tie-in Expn CP97-319 Pending Expn 30 NA 750

1999 IN IL Midwest C10 Crossroads/CNG -- Announced Expn 20 NA 150

1999 MN MN Midwest C11 Great Lakes Carlton Project CP98-96 Pending Expn 4 9 67

1998 MI MI Midwest C12 Great Lakes Sault Looping CP98-143 Pending Expn 14 11 0

1999 IL IA Central C13 Northern Natural Gas East Leg 2000 -- Announced Expn 264 835 450

1999 OH TN Southeast C14 Tenneco Eastern Express -- Announced Expn NA 200 500

1999 MI IL Midwest C15 Vector Pipeline (US Portion) -- Pending New 328 447 1,000

2000 IL SK Canada C16 Alliance Project (US Portion) CP97-168 Pending New 886 600 1,325

2000 MI MB Canada C17 Great Lakes 300 Expn CP98-309 Pending Expn 258 620 312

2000 IN SK Canada C16 Northern Border Project 2000 -- Announced Expn NA NA 400

2000 MI IL Midwest C19 TriState Pipeline Project -- Announced New 275 NA 500

2000 IL MB Canada C20 Viking Voyageur Project NA Pending New 773 1,240 1,400

Total New Capacity 8,234

Northeast

1998 VA PA Northeast D1 Columbia Gas Market Expn II CP96-213 Pending Expn 379 21 167

1998 VA VA Northeast D2 East Tenn Roanoke Expn CP98-40 Pending Expn 60 NA 10

1998 MD DE Northeast D3 Eastern Shore System Expn NA Pending Expn 98 NA 5

1998 NY QU Canada D4 Iroquois Import Expn CP96-687 Pending Expn 200 22 35

1998 PA NY Northeast D5 National Fuel Niagara/Leidy I CP98-94 Approved Expn 139 5 23

1998 ME MA Northeast D6 Portland/Maritimes & Northeast I CP97-238 Approved New 100 175 631

1998 ME QU Canada D7 Portland Pipeline Project CP95-248 Approved New 293 303 178

1998 MA MA Northeast D8 Tenneco/DOMAC CP96-164 Pending New 8 26 55

1998 PA PA Northeast D9 Texas Eastern Virginia Natural Expn CP96-606 Pending Expn NA NA 20

1998 VT QU Canada D10 Vermont Gas System Import Expn CP97-324 Approved Expn 190 NA 9

1998 VA VA Northeast D11 VNG Saltville P-25 Line -- Approved Expn 72 15 30

1999 VA PA Northeast D12 CNG PL-1 Phase II CP96-492 On Hold Expn NA NA 25

1999 NY ON Canada D13 Columbia’s Millennium PL CP98-150 Pending New 442 683 700

1999 PA WV Northeast D14 CNG SSE Expn CP96-492 On Hold Expn 40 35 178

1999 PA OH Midwest D15 CNG Market Value Project NA Announced Expn NA NA 150

1999 VA PA Northeast D16 CNG MAS (Market Area Storage) CP97-774 Pending Expn NA NA 10

1999 VA PA Northeast D1 Columbia Gas Market Expn III CP96-213 Pending Expn 379 20 108

1999 PA OH Midwest D17 Independence Pipeline CP97-315 Pending New 400 678 1,001

1999 ME NB Canada D18 Maritimes & Northeast II (US Portion) CP96-809 Approved New 386 425 440

1999 ME QU Canada D7 Portland Pipeline 1999 Expn -- Announced Expn NA NA 500

1999 PA PA Northeast D9 Texas Eastern Virginia Natural Expn CP96-606 Pending Expn NA NA 12

1999 NY PA Northeast D20 Transco MarketLink Expn -- Announced Expn 2 600 400

1999 NY NJ Northeast D21 Duke Energy Crossbay Project -- Announced New 44 NA 700

1999 VA VA Northeast D22 VNG Saltville P-24 Line -- Pending Expn 40 NA 50
Table B2. Major Proposed Natural Gas Pipeline Construction Projects, by Terminating Region and

Planned In-Service Year, 1998–2000 (Continued)

Year State State Region Key Pipeline/Project Name Number 3-31-98 Expansion Miles (million $) (MMcf/d)

Ends FERC Status New Cost Added

in Begins in Map Docket As of or Estimate Capacity a

Energy Information Administration

124 Deliverability on the Interstate Natural Gas Pipeline System

2000 MA NH Northeast D23 Algonquin HubLine Project -- Announced New 70 NA 600

2000 NY IL Midwest D24 Duke Energy Spectrum PL -- Announced Expn 370 600 500

2000 NF NH Canada D19 MarineLine Subsea Project CP98-30 On hold New 1,570 3,500 400

2000 NY QU Canada D25 Iroquois NY City Expn -- Announced Expn 27 NA 160

2000 PA ON Canada D26 Tenneco Niagara-Leidy Expn -- Announced Expn NA NA 200

2000 MA TN Southeast D27 Tenneco Eastern Express 2000 -- Announced Expn NA 200 700

2000 PA PA Northeast D9 Texas Eastern Virginia Natural Expn CP96-606 Pending Expn NA NA 12

2000 VA VA Northeast D28 VNG Tidewater Intrastate PL -- Announced New 350 NA 315

Total New Capacity 8,324

Southeast

1998 AL GM Offshore E1 DIGS (Dauphin Island) Phase II CP98-6 Approved Expn 13 19 169

1998 MS GM Offshore E2 Destin Corridor Offshore CP96-655 Approved New 220 294 1,000

1998 GM GM Offshore E3 Destin Main Pass Laterals CP98-238 Pending Expn 13 19 230

1998 GA AL Southeast E4 SONAT Zone 2 & 3 Expn CP96-526 Approved Expn NA 52 65

1998 AL AL Southeast E5 SONAT Dallas County Expn CP97-691 Approved Expn 3 4 34

1998 TN TN Southeast E6 Tengasco East Tennessee PL Link -- Approved New 10 6 10

1998 GA AL Southeast E7 Transco Cherokee Project CP97-331 Approved Expn 16 68 87

1998 MS GM Offshore E8 Transco Mobile Bay Expn CP97-92 Approved Expn 76 120 350

1998 AL TN Southeast E9 U.S. Gypsum Lateral CP97-202 Approved New 15 4 21

1999 KY LA Southwest E10 Columbia Gulf Mainline Expn -- Announced Expn 820 NA 218

1999 NC NC Southeast E11 Cardinal Pipeline (Transco) -- Approved Expn 67 98 140

1999 GA AL Southeast E12 SONAT/East Tenn Connection CP96-153 Approved Expn 123 66 76

1999 TN LA Southwest E13 Tenneco Express 500 Expn NA Announced Expn NA NA 220

1999 NC NC Southeast E14 Transco Pine Needle LNG Link CP96-134 Approved New 1 1 400

2000 TN GA Southeast E15 Cumberland Pipeline (Transco) -- Pending Expn NA NA 200

Total New Capacity 3,221

Southwest

1998 LA GM Offshore F1 ANR Conch Project CP97-71 Approved Expn 37 51 461

1998 TX TX Southwest F2 Coastal States Roma Export Line -- Approved New 18 51 170

1998 NM NM Southwest F3 El Paso San Juan Expn -- Pending Expn 34 4 116

1998 LA LA Southwest F4 Mid-Louisiana Baton-Rouge Expn -- Announced Expn 25 NA 100

1998 TX TX Southwest F5 MidCon Texas Pipeline CP96-140 Approved New 15 1 270

1998 LA LA Southwest F6 Noram Gas Trans Line-F Expn CP97-724 Approved Expn 90 32 170

1998 LA GM Offshore F7 Shell Mississippi Canyon Expn NA Announced Expn NA NA 300

1998 LA LA Offshore F8 Tenneco South Pass 77 Expn CP98-220 Pending Expn -- 1 400

1998 LA LA Southwest F9 Texas Gas PL Hougton Expn CP97-656 Approved Expn NA 6 115

1998 GM GM Offshore F10 Transco Sealeg Project CP96-758 Approved Expn 51 80 331

1998 NM CO Central F11 Transwestern San Juan Expn I CP97-516 Approved Expn 33 21 115

1998 NM NM Southwest F12 Transwestern San Juan Expn II CP97-516 Approved Expn 110 21 130

1998 LA GM Offshore F13 Trunkline Terrebone Expn CP97-105 Approved Expn 145 52 500

1998 GM GM Offshore F14 Williams Natural Gas Genesis Expn -- Pending New 35 NA 72

1999 LA TX Southwest F15 ANR Katy Project -- On hold New 220 51 200

1999 LA GM Offshore F16 Transco Crossover Project -- Announced New/Expn 170 NA 264

Total New Capacity 3,715

Western

1998 WA OR Western G1 Northwest PL Columbia River Extn -- Announced Expn NA 17 50

1998 WA BC Canada G2 PGT Mainline Expn -- Announced Expn -- 6 76

1998 CA CA Western G3 Pacific Offshore Santa Barbara Expn -- Approved Expn NA NA 20

1998 CA CA Western G4 San Diego G&E Pipeline 2000 CP93-117 Approved New 80 85 40

1999 NV ID Western G5 NWPL Silver Gem Lateral -- Announced New 121 79 93

1999 NV NV Western G6 Pauite Silver Gem/Elko Expn -- Announced Expn 43 NA 55

2000 NV UT Central G7 CIG Utah-Nevada Line -- Announced New 360 NA 250

Total New Capacity 584

Mexico

1998 MX TX Southwest H1 Coastal States Roma Export Point CP96-770 Approved New 1 NA 170

1998 MX TX Southwest H2 MidCon Texas Roma Export Point CP96-583 Approved Expn 1 NA 270

1999 MX NM Southwest H3 PNM Gas Services Export CP93-98 Approved New NA NA 35

1999 MX TX Southwest H4 Houston Pipeline Export CP92-417 On hold New 22 NA 600

1999 MX CA Western H5 SoCal Project Vecinos CP94-207 Approved New 8 100 300

Total New Capacity 1,375

Announced = Prior to filing with regulatory authorities. Pending = Before regulatory authority for review and acceptance. Approved = Fully or a

conditionally approved by regulating authority; may or may not be under construction. On Hold = May be canceled or postponed due to changed

market or regulatory conditions.

Cost and added capacity are the same for this and previous line item. b

 MMcf/d = Million cubic feet per day. Expn = Expansion. NA = Not available. -- = Not applicable. Extn = Extension. CIG = Colorado Interstate

Gas Co.; CNG = CNG Transmission Co; DIGS = Dauphin Island Gathering System; GM = Gulf of Mexico; NGPL = Natural Gas Pipeline Co. of

America; NSPC = Northern States Power Co.; NWPL = Northwest Pipeline Co.; PSCO = Public Service Co. of Colorado; SoCal = Southern California

Gas Co.; SONAT = Southern Natural Gas Co.; Tenneco = Tennessee Gas Pipeline Co.; TCPL = TransCanada Pipeline Ltd.; Transco =

Transcontinental Gas Pipeline Co.; VNG = Virginia Natural Gas Co.

Notes: All cost estimates are in U.S. dollars. Bold underlined items indicate project crosses regional boundary.

Source: Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Proposed Pipeline Construction Database,

as of March 1998, compiled from Federal Energy Regulatory Commission filings and various industry news sources.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 125

San Juan Basin (New Mexico) Access

Until recently, the capacity available to move gas from the

San Juan Basin area eastward was limited. The rapid

development of the area’s coalbed methane and other supplies

in the area during the late 1980's led to an excess in

productive capacity. Originally the new production was

expected to be consumed in the California market, and

pipeline capacity was developed with that in mind. Today,

however, the emphasis is on finding ways to expand

deliverability for producers in the basin and move some

of this supply eastward to link with market centers in the

Texas Panhandle as well as those located in the Waha area of

southwestern Texas. From there the gas could be redirected

through northern and eastern Texas to Midwest and Northeast

markets. The two major interstate pipeline companies in the

area, Transwestern Pipeline Company and El Paso Natural

Gas Company, have undertaken efforts to expand and In the past, Rocky Mountain supplies (Colorado, Wyoming

enhance facilities on their respective systems, which would and Utah) generally moved to a strong southern California gas

allow them to direct more production eastward to the market, but the current emphasis of area producers is to

Waha/Permian Basin centers. increase their presence in local energy markets and to extend

In 1997, both pipeline companies completed projects 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 access to these relatively lower

several additional projects that would relieve the ongoing priced supplies. 

capacity constraint issue in the area. For instance,

Transwestern Pipeline Company added an additional In 1997, several natural gas pipeline projects were completed

25 MMcf/d with the expansion of compression on its system that furthered that goal. For instance, KN Interstate Pipeline

within the basin (Table B1). It also has Federal Energy Company placed its “Pony Express” line (0.26 Bcf/d) in

Regulatory Commission (FERC) approval to expand its local service in August and the Trailblazer/Overthrust/Wyoming

capabilities by 245 MMcf/d in 1998. El Paso Natural Gas Interstate system (0.1 to 0.2 Bcf/d) expansion was completed

Company also plans to expand its local San Juan Basin in the last quarter of the year. The latter expansion increased

capabilities by 116 MMf/d in 1998 (pending FERC approval) the system’s deliverability to its interconnection with the

in response to rising production demands. Natural Gas Pipeline Company of America’s Amarillo line,

In addition, with the completion of the full TransColorado

Pipeline system (from northern Colorado to northern New The proposed pipeline expansion projects in the area, for the

Mexico) in 1998, a portion of its 0.3 Bcf/d capacity could be most part, target expanding regional service as an outlet for

available to local producers/shippers on an as-available basis. expanding area production. Two major project proposals, the

The El Paso Natural Gas Company’s completed its Havasu (Table B2), both intend to transport Wyoming supplies to a

Crossover expansion project in mid-1997. This project uses growing Denver, Colorado, marketplace. The Questar

expanded capacity on the westward-bound portion of the Pipeline Company proposes to expand its capabilities in the

system to move supplies that are redirected eastward (either Salt Lake City area. 

physically or by displacement) just east of the California

border. The expansion upgraded the Havasu Crossover, which In addition to the expanding production in areas of the Rocky

links the north and south parts of the El Paso system. These Mountains located in Wyoming, Utah, and northern Colorado,

system enhancements increased El Paso deliverability in the the Powder River area of southern Montana and northern

Waha area of West Texas by an additional 180 MMcf/d. Wyoming is expected to develop into a major producing area

 over the next decade. Already several of the pipeline projects

Potential East and South Texas Expansions

Although no pipeline projects have been proposed for the

area, the Cotton Valley Trend of East Texas is expected to

become a major new source of gas production 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 accommodate current and future new

production. The question remains, however, whether current

interstate capacity levels, which are not fully utilized at the

present, can handle the new production without expansion.

The proposed ANR Katy project, which was, in part, targeted

at shippers who potentially might want to access this new

production, did not generate as much interest as the company

expected when an “open-season” was offered in mid-1997.

The future of the project is currently under review by the

company.

Rocky Mountain Area Access

their customer base further in U.S. Midwestern and Eastern

which transports supplies to the Midwest Region.

KN Interstate Pipeline Company’s Front Runner projects

discussed earlier have anticipated access to this area’s

production in their design.
Energy Information Administration

126 Deliverability on the Interstate Natural Gas Pipeline System

Improved Access to Canadian Supply

During 1997, the TransCanada Pipeline system increased its

domestic deliverability by 119 MMcf/d and expanded several

of its export points to the United States. However, only one of

the interconnecting U.S. pipelines (Viking Gas Transmission

Company) expanded its capacity accordingly. The

TransCanada export upgrades were primarily to alleviate

some of its own limitations. Most of the U.S. pipelines were

already capable of accepting the increased flows.

The completion of these projects in 1997 only partially

relieved the existing capacity constraint problem on the

TransCanada system. Flow restrictions on the system have

limited western Alberta (Canada) natural gas producers’

access to markets to the east during the past several years.

However, within Canada, a number of projects are planned

that will improve operational flows significantly and add to

export capability. Although it is doubtful that all will be built,

11 projects within Canada, representing more than 8.6 Bcf/d

of new capacity, have been proposed for development by 125

the end of 2000. Several, like the NOVA system expansion

and the new ANG Kootenay Pacific Pipeline, would increase

production area exit capacity. However, the bulk of the new

capacity that is being proposed would be longhaul system

capacity targeted for eastern Canadian natural gas markets

(which are growing rapidly) and to expand export capabilities

(Figure B3).

Reflecting the growing Canadian production and desire to

flow more of that gas to U.S. markets, 14 projects have been

proposed that could add as much as 5.9 Bcf/d to U.S. import

capacity from Canada during the next 3 years, an increase of

52 percent from the 1997 level. The volume increase is 126

17 percent more than the total Canadian import capacity

added from 1991 through 1997, 5.0 Bcf/d (see Chapter 3).

This anticipated growth also reflects the continuing U.S.

demand for Canadian natural gas, especially in the Midwest

and Northeast regions.

These efforts include several very large projects. For example,

a new natural gas pipeline (the Alliance project) would bring

gas from British Columbia to the Chicago, Illinois, area along

the right-of-way of an existing oil pipeline. Several other

projects are competing with the Alliance project, including

the Viking Voyageur Pipeline, which is a 1.4 Bcf/d line

between the Noyes, Minnesota, import point and the Chicago,

Illinois, area, and the Northern Border Project 2000, which is

a 400 MMcf/d expansion that includes a proposal to extend 127

the system to Indiana and possibly to the Michigan-Canada

border to serve the Ontario marketplace. (Note: In late April

1998 the sponsors of the Viking Voyageur Project announced

that it was unlikely that they would be able to secure enough

future shipper commitments and available production in

Canada to make the project viable at its proposed level. As a

result, the project may terminate or downsize. Since its

1999/2000 expansion plans are predicated in part upon the

Viking Project, TransCanada Pipeline’s expansion plans may

have to cut back 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 MMcf/d, respectively, during the

next several years.

Because 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

accommodate an interconnection with the Viking Voyageur

project and larger potential demand in the Canadian domestic

market. The new capacity would be phased in over 2 years

beginning in 1999. Currently, TransCanada is in the process

of revising its expansion plans for 1999 to reflect its

commitments to the Voyageur expansion. 

In August 1996, the Federal Energy Regulatory Commission

approved construction of the Northern Border Pipeline

Company expansion project, which would add 0.7 Bcf/d to

import capacity at the Montana border. Correspondingly,

Foothills Pipe Line Ltd. of Canada, which interconnects with

Northern Border Pipeline at Monchy, Montana, would expand

its eastern leg by the same amount. 

On the Canadian east coast, several new pipelines have been

proposed to move gas supplies being developed off the

Canadian Atlantic coast near Sable Island to markets in

Canada and the United States (Table B2). The Maritimes &

Northeast pipeline project would move Sable Island supplies

to the Northeastern United States. The Maritimes & Northeast

pipeline project’s route will take it directly into the State of

Maine and through New Hampshire to interconnections with

the Tennessee Gas Pipeline system in Massachusetts. Another

project, the MarineLine Subsea pipeline has been proposed.128

It would not only provide an alternative transportation route Final capacity levels for TransCanada Pipeline Company’s 1999 125

expansion effort were not available as of March 1998.

Does not include two projects, representing 1.1 Bcf/d capacity, whose 126

chances of success are marginal. It also does not include the Columbia Original plans were for a 1.3 Bcf/d expansion, but the project’s size has

Millennium project into the Northeast Region whose capacity is tied in with been cut because of less-than-expected market interest.

the import capacity into the Midwest and the 1.6 Bcf/d Alliance Pipeline In March 1998, this project was placed in an inactive status, pending

import station, which for the most part is accounted for in that project. completion of additional geological and geophysical surveys.

127

128
Altamont Pipeline

 (New)

PG&E Transmission-NW

 (Expansion)

Nova & ANG Pacific 

 (Expansion)



Foothill Pipeline Co

 (Expansion)





Northern Border Pipeline Co

 (Expansion)

 (New Section)

PanEnergy's Spectrum

 (Expansion)

 

Natural Gas PL of America

 (Expansion)

TriState Pipeline 

 (New)

TransCanada Pipeline LTD

 (Expansion)





Viking Voyageur

 (New)



 

= Expansion Direction

Tenneco Eastern Express

 (Expansion)

Great Lakes Transmission Co

 (Expansion)

Alliance Project 

 (New)

Viking Transmission Co

 (Expansion)







Vector Pipeline 

 (New)

Independence Pipeline

 (New)



Phase I

Iroquois Pipeline Co

 (Expansion)

Columbia's Millennium 

 (Expansion)





Portland Pipeline

 (New) 

Phase II

Maritimes & Northeast 

 (New)

MarineLine Subsea

 (New)

Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 127

Figure B3. Planned Projects Related to Imports of Canadian Gas, 1998-2000

Source: Energy Information Administration (EIA), EIAGIS-NG Geographic Information System, Natural Gas Pipeline Construction Database,

as of March 1998.

from Sable Island but also would handle receipts (supplies) by the end of 2000, with 8.2 Bcf/d of new interstate capacity

from as far north as Newfoundland, through a sea route planned overall, the second highest of the six regions. But

passing through the Sable Island fields and southward to what really distinguishes the growth in the Midwest is that the

landfall in New Hampshire. vast majority of new capacity would be on newly built

Market Areas 

Midwest

In 1997, only three interstate pipeline projects were

completed in the Midwest Region (Table B1), adding

441 MMcf/d of new capacity. These projects represented an

increase to intraregional capacity of only about one-half of

1 percent. However, one project (ANR Michigan Leg

expansion) resolves a capacity bottleneck in the region, while

the other two expanded deliverability to growing markets in

Wisconsin and vicinity.

Based upon current proposals, natural gas pipeline

deliverability to the Midwest Region will grow substantially

trunklines or extensions to existing pipelines bringing

supplies from Canada. Ten of these projects would increase

interregional deliverability by a total of 5.3 Bcf/d. The

Midwest will be the terminus for the Alliance project, which

alone would increase area service by 1.3 Bcf/d. Excluding the

extension of Canadian supplies via the Northern Border

Pipeline to Manhattan, Illinois (near Chicago), and Natural

Gas Pipeline Company of America’s (NGPL) Amarillo

expansion (110 MMcf/d) destined for the same area, the

Midwest Region’s access to Canadian supplies could increase

by as much as 117 percent (3.6 Bcf/d) from the 1997 level

(3.0 Bcf/d).

Two new pipelines, TriState (0.5 Bcf/d) and Vector

(1.0 Bcf/d), have been proposed to tranship supplies arriving

via Voyageur, Alliance, and Northern Border pipelines in the

Chicago area to markets in eastern Michigan and southern
Energy Information Administration

128 Deliverability on the Interstate Natural Gas Pipeline System

Ontario, Canada. The Vector pipeline would provide an Southwest to the Midwest to reach customers in the

integral link in support of Columbia Gas Transmission Northeast.

Company’s Millennium project, which has been proposed to

begin gas deliveries in the fall of 1999 to customers in the Other projects that would move some of the new Midwestern

Northeast (see next section). Vector would tranship supplies pipeline supplies eastward include Tennessee Gas Pipeline

through Canada via the Union Gas System (Ontario) from the Company’s proposed Eastern Express project and Duke

St. Clair export point and Dawn (Ontario) storage to the Energy Corporation’s Spectrum project. These two projects

Millennium pipeline at Niagara, New York. alone represent a total of 1.2 Bcf/d of new capacity into the

Northeast

More pipeline expansion projects were completed in the

Northeast Region in 1997 than in any other part of North

America. Twelve projects, accounting for about 770 MMcf/d

of additional deliverability, or 2 percent of intraregional

pipeline capabilities, were placed in service. However, only

one of these projects (24 MMcf/d) increased interregional

deliverability (Table B1). The capacity increase within the

region was exceeded only in the Southwest Region. Almost

all of the projects were to improve deliverability within local

markets or to address bottlenecks that were limiting service in

areas of growing demand. Texas Eastern Transmission’s

several expansion projects were implemented primarily to

resolve the latter problem.

The Northeast has the most natural gas pipeline projects (28)

slated for development and they represent the largest amount

of proposed new pipeline capacity within any region of the

United States, 8.3 Bcf/d. Several of the projects are

continuations of ones that began in 1996 or 1997 and are

being phased in over several years. While many of the

proposed projects are smaller regional expansions serving

local market areas, more than 59 percent of the added

capacity would be on pipeline systems delivering from

outside the Northeast Region. Of the 5.0 Bcf/d of proposed

new interregional capacity, more than 53 percent would carry

supplies originating in Canada.

Many of these projects have been planned because of

expectations that an excess deliverability situation could

occur in the Chicago area if all the projects slated to bring

Canadian supplies into the Midwest are completed. This

possibility has spurred several companies to plan large-scale

projects that would extend some of this new capacity further

eastward to Northeast markets. For example, ANR Pipeline

Company and Transcontinental Gas Pipeline Company have

proposed the jointly owned Independence project, which

could carry 1.0 Bcf/d from ANR’s line in northwestern Ohio

to a major interconnection with Transcontinental’s line in

Leidy, Pennsylvania, a major hub serving the Northeastern

marketplace. The new line would also be attractive to

Canadian-gas shippers seeking an alternative route to

Northeast markets. It could also provide an alternative route

and opportunity for shippers now moving gas from the

Northeast. Including the Independence and Millennium

projects, as well as other import projects slated for

development during the next several years, new capacity into

the region could reach 5.2 Bcf/d, adding significantly to the

12.4 Bcf/d existing at the close of 1997.

The Spectrum project (0.5 Bcf/d) would extend from the

Chicago, Illinois, area to New York and New England, mostly

using expanded facilities along Duke Energy’s affiliated

pipelines: Panhandle Eastern, Texas Eastern, and Algonquin

Gas Transmission systems (west to east). In addition, an

interconnection with another affiliate, Trunkline Gas

Company, could be utilized to move gas supplies from the

Southwest Region if appropriate (as could the Panhandle

Eastern Pipeline system). The Eastern Express project

(0.7 Bcf/d) would utilize Midwestern Gas Transmission

Company (an affiliate of Tennessee Gas Pipeline Company)

to ship supplies southward (or though displacement) to

Tennessee Gas’s interconnection in northern Tennessee and

then, through expanded facilities on its existing system,

transport supplies from the Midwest to the east coast. In

addition, the Eastern Express project would include expansion

(0.2 Bcf/d) of Tennessee Gas’s pipeline between its Niagara,

New York, import point and its interconnections near Leidy,

Pennsylvania, and its northern line extending directly to New

England.

Canadian import expansions slated for development in 1998

and 1999 will result in increased capacity at several import

points into the Northeastern United States and development

of at least one new import point (for Columbia Gas

Transmission’s Millennium project). For example, in response

to TransCanada’s multiyear expansion plans, Iroquois

Pipeline Company has proposed to expand its system by

about 195 MMcf/d, phased in during 1998 and 2000. Also

supported by the TransCanada expansion will be the new

Portland Natural Gas Pipeline (178 MMcf/d), which would

replace and expand Granite State Pipeline Company’s leased

line (31 MMcf/d) that currently brings Canadian gas to Maine

via Vermont and New Hampshire. Combined with the

Millennium import level of 0.7 Bcf/d and several import

expansions related to other projects, direct Canadian export

capacity to the U.S. Northeast could increase by about

2.6 Bcf/d by the end of 2000, a 91-percent increase over the

1997 level.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 129

Planned expansions in the Northeast Region are also of proposed capacity additions, all of which are scheduled to

somewhat unique in that several projects represent be in service sometime in 1998.

cooperative efforts among regional pipeline systems. For

example, the Texas Eastern expansion of service to some of Five of these projects (1.2 Bcf/d of expansion capacity)

its Virginia and eastern Pennsylvania service areas depends represent an increased commitment by Transcontinental Gas

partly upon the completion of the CNG Transmission PL-1 Pipeline Company to customers within the region. Four other

line and Seasonal Service expansion projects, including projects also represent greater service to regional markets,

improvements to storage deliverability. Columbia Gas especially in the Atlanta, Georgia, area and the service

Transmission, with its “Market Expansion” project, is also territory of Atlanta Gas Light Company. Growth in the

planning improvements (especially to storage services) on its regional industrial market is helping to spur demand for

system that would increase deliverability to several major additional natural gas supplies.

interconnections 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 projects that are designed to transport some of the

completion of projects by Columbia, CNG, and Texas growing Southwest regional production through the Southeast

Eastern. In particular, National Fuel’s project will to markets in the Midwest and Northeast. The Tennessee Gas

complement CNG’s planned improvement to its system for Pipeline Company’s Express 500 is one such proposal, with

flowing gas between Leidy, Pennsylvania, a major storage up to 0.2 Bcf/d additional capacity to be added by 2000,

area and hub interconnection point, and Steuben County, New increasing the existing capacity of its Line 500 located within

York, and then northward where CNG and National Fuel have the region. Columbia Gulf Transmission Company also will

major interconnections. The first phases of several of these increase its mainline capacity by more than 0.2 Bcf/d. For the

projects were completed in 1997. past several years, Columbia Gulf system has been operating

Of the 28 singular projects planned within the region infrastructure; the problem would be resolved with the

representing 8.3 Bcf/d of new capacity, a number are either completion of this project. 

directly or indirectly linked by mutual service needs or

partnerships. These projects constitute about 18 percent, or 129

1.1 Bcf/d, of the new capacity additions in the region.

Southeast

Natural gas pipeline expansions completed in the Southeast (237 MMcf/d) were completed in 1997. These were the first

Region in 1997 (436 MMcf/d) were intended mainly to new export points to Mexico installed in 5 years (Table B1).

improve Deliverability within the region, primarily in North None of the proposed projects represents enhancements to

and South Carolina, Georgia, and Alabama. These expansions import capabilities, currently at about 350 MMcf/d, a figure

represent less than 1 percent of the total 1996 regional that has not changed since the 1980s. All of the proposed

pipeline capacity levels (Table ES1). One system, projects are to support mostly industrial and power generation

Transcontinental Gas Pipeline Company, was involved in customers located in the border area. 

three of the five projects completed in 1997. In addition to

increasing service from its North Carolina mainline, If completed, the currently proposed projects would represent

completion of its Sunbelt project supported the expansion of about 1.4 Bcf/d of additional export capacity (Table B2).

the South Carolina Pipeline system, which was also Currently (1997), export capacity to Mexico stands at 1.1

completed in 1997. Bcf/d. Several of the proposed projects are competing within

Fifteen expansion projects, representing a potential 3.2 Bcf/d Texas Pipeline Company (Figure B2) and Coastal States Gas

of new capacity development, are proposed for the Southeast Transmission Company are seeking to negotiate with

Region. About 54 percent of this capacity is geared toward Mexican buyers for firm shipping agreements to essentially

improving regional access to deep water production in the the same general area. Nevertheless, both companies view

Gulf of Mexico. Offshore projects represent about 1.7 Bcf/d their projects as proceeding regardless of the outcome of

below its original design capacity because of an aging

Mexico Market

Several projects have been proposed to add to the export

capability of U.S. natural gas companies located near the

border with Mexico (Table B2), although only two projects

and for the same market. For example, Both the MidConnegotiations. These two companies also have plans to

construct pipelines within Mexico that will link with their

border crossing project and Texas intrastate pipeline

construction projects. Transcontinental Gas Pipeline Company and Tennessee Gas Pipeline 129

Company also have several projects in the region that will benefit from and

support expansions in the region.
Energy Information Administration

130 Deliverability on the Interstate Natural Gas Pipeline System

Most of the proposed projects have been proceeding slowly capacity (Table ES1). Although it is unlikely that all proposed

for environmental, economic, and regulatory reasons. One expansions will be completed, additional projects continue to

obstacle has been overcome with the installation of Mexico’s be proposed. During 1997 and early 1998, for instance, at

newly formed regulatory authority, the Comision de Energia least 22 pipeline companies instituted open-season exercises

(CRE). The CRE has issued less restrictive regulations on for 26 projects, with the expectation that the market will

foreign investment in Mexico, which affects the ownership support additional expansion plans. These proposals, while

and operation of pipeline facilities owned by others. In the fall not all sussessful, included expansions in all regions of the

of 1996, the CRE announced its first award of a country.

(privatization) license permitting the development of a local

gas distribution system in the Baja area of northern Mexico. Beyond what has already been proposed, there are areas of the 130

This action may hasten the approval and final implementation country where additional pipeline expansion plans might

of several similar local service development proposals, which develop in response to changing market profiles and the

are linked to pending U.S. export proposals that have development of new supply sources. For instance, deep-water

remained dormant for several years. development in the Gulf of Mexico will continue over the

In December 1997, construction was completed on the El onshore expansions. In addition, the expanding production in

Paso Energy Company’s Samalayucca project, which links areas of Texas and the Rocky Mountains will place pressure

Texas supply sources with customers in Mexico’s Chihuahua on local pipeline systems to expand their capabilities to reach

State. The 45-mile, 210 MMcf/d pipeline is the first pipeline nearby and distant markets. As a consequence, utilization

located in Mexico owned in part by a U.S. company. A major rates on interconnecting interstate pipelines should increase

customer of the project will be a 700 megawatt combined- and, in some cases, necessitate the development of new

cycle electric generating plant located in Samalayucca, capacity on some systems.

Mexico, which will begin operations in late 1998. 

Summary

The amount of new capacity proposed for development by the

end of 2000 is significant and, if fully implemented, would

represent a 9-percent increase in intraregional capacity from

the 1996 level and a 17-percent increase in interregional

next decade and with it could come additional complementary

The upcoming major increase in capacity from Canada to the

U.S. Midwest may also spur additional development of new

pipelines, or expansions of existing lines, that can provide

alternative capacity for transhipment of some of this gas to the

U.S. Northeast. Already several of the proposed Midwest-toNortheast expansion projects are premised on the assumption

that excess capacity into the Chicago, Illinois, area could

develop over the next several years as new (proposed

Canadian source) pipelines are completed during the interim.

The award was made to a consortium consisting of Pacific Enterprises 130

International (PEI), Enova International Corporation, and Proxima. The license

will permit the group to transport gas from PEI’s local system in lower

California into the city of Mexicali in northern Mexico.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 131

Appendix C

Changes in Natural Gas Markets

This appendix presents several State summary data tables that These changes reflect the shifts in consumption patterns that

detail energy use profiles of the geographic regions covered have occurred as a result of market restructuring at both the

in this report and the availability of supplemental natural gas national and local levels. They also reflect changes in market

supplies. These tables supplement the regional tables in demand as a result of changes in a State’s economic profile

Chapter 5, “Deliverability to Markets.” 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 basic 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 consumers for each end-use

determinant of natural gas demand) and levels of underground sector in 1996 and the average annual growth rate from 1990

and liquefied natural gas (LNG) storage. How much gas can through 1996. The change in these factors underlies the level

be delivered from storage facilities and is available to the and magnitude of the movements reflected in the market

pipeline network during peak periods are crucial factors in shares for natural gas customer groups. 

analyzing the ability of the pipeline system to support

estimated consumer requirements. Most of the annual data used to compile the annual average

The second table, Table C2, “Regional and State Energy following Energy Information Administration publications:

Profile Comparison of Annual Average Change,” shows total the Natural Gas Annual, the Electric Power Annual, or the

energy consumption patterns for each of the lower 48 States, State Energy Data Report (SEDS). While the period of

in particular how the use of natural gas increased (decreased) comparison, for the most part, was for the years 1990 through

relative to all other fuel types between 1990 and 1995. The 1996, in some instances data were not yet available for 1996.

third table, Table C3, “Regional and State Natural Gas Specifically, the SEDS data, which tabulate all annual energy

Customer Market Share Changes,” illustrates how the use of use data on a common (Btu) basis, are not compiled until all

natural gas among the various natural gas customer sectors individual fuel data are verified and complete; they were

within each State has changed since 1990. available only through 1995 when this report was prepared.

rates of change shown in these tables may be found in the
Energy Information Administration

132 Deliverability on the Interstate Natural Gas Pipeline System

Table C1. Regional Weather and Gas Storage Profile, 1996

Region State 1990) Coldest) (MMcf) (MMcf/d) (percent) (percent) Operated Independents Operated (MMcf) (MMcf/d)

Number of Normal Weather

Interstate Heating Ranking From From Percent

Pipelines Degree Among Working Convent- High- Percent Percent LDC

Operating Days States Gas ional Deliverability Interstate Operated Owned Peak-Day

in (1960- (1 = Capacity Total Storage Storage Pipeline by and Capacity Support

Natural Gas Underground Storage - 1996 LNG Peaking

Supplies

Peak-Day Withdrawal Capability (Deliverability) 1996

Central

Colorado 9 7,123 10 52,261 1,112 100 0 76 0 23 -- --

Iowa 4 6,932 12 74,100 1,000 100 0 100 0 0 3,843 364

Kansas 9 4,988 29 109,291 2,409 93 7 88 8 4 -- --

Missouri 8 5,091 28 9,526 350 100 0 0 0 100 -- --

Montana 5 8,260 3 207,622 283 100 0 40 0 60 -- --

Nebraska 6 6,435 15 7,962 101 100 0 100 0 0 1,078 52

North Dakota 3 9,481 1 -- -- -- -- -- -- -- -- --

South Dakota 3 7,714 7 -- -- -- -- -- -- -- -- --

Utah 4 6,555 14 59,880 520 100 0 99 0 1 -- --

Wyoming 6 8,023 4 45,251 261 100 0 86 0 14 -- --

Total 21 7,061 1 565,894 6,037 97 3 81 3 16 4,921 416

Midwest

Illinois 9 6,175 17 246,771 6,435 100 0 29 0 71 1,063 259

Indiana 7 5,871 23 41,034 757 100 0 17 0 83 10,287 797

Michigan 6 6,823 13 633,912 11,964 99 1 33 13 54 -- --

Minnesota 5 8,771 2 2,377 60 100 0 0 0 100 5,412 1,520

Ohio 9 5,897 21 206,379 4,782 100 0 40 0 60 -- --

Wisconsin 5 7,665 8 -- -- -- -- -- -- -- 960 109

Total 17 6,867 2 1,130,475 24,000 99 1 33 6 61 17,722 2,685

Northeast

Connecticut 3 6,146 18 -- -- -- -- -- -- -- 2,394 130

Delaware 3 4,784 31 -- -- -- -- -- -- -- 265 43

Maine 1 7,945 6 -- -- -- -- -- -- -- 14 48

Maryland/DC 5 4,811 30 15,322 306 100 0 100 0 0 1,055 215

Massachusetts 3 6,322 16 -- -- -- -- -- -- -- 11,559 952

New Hampsh. 1 7,599 9 -- -- -- -- -- -- -- 400 50

New Jersey 5 5,424 25 -- -- -- -- -- -- -- 8,822 736

New York 12 5,943 20 82,889 1,094 92 8 83 9 8 3,399 524

Pennsylvania 9 5,881 22 378,016 7,022 100 0 94 0 6 625 540

Rhode Island 2 5,968 19 -- -- -- -- -- -- -- 2,324 128

Vermont 2 7,979 5 -- -- -- -- -- -- -- -- --

Virginia 4 4,327 34 1,930 55 27 73 72 28 0 922 393

West Virginia 5 5,250 27 191,684 3,223 100 0 96 0 4 -- --

Total 15 6,029 3 669,842 11,701 98 2 94 0 6 31,765 3,759

Southeast

Alabama 9 2,828 40 2,090 260 0 100 0 0 100 2,207 344

Florida 3 720 48 -- -- -- -- -- -- -- -- --

Georgia 4 2,788 41 -- -- -- -- -- -- -- 10,756 1,122

Kentucky 9 4,544 33 113,467 1,725 100 0 67 1 32 -- --

Mississippi 14 2,510 44 56,860 3,220 32 68 77 20 3 -- --

North Carolina 1 3,481 38 -- -- -- -- -- -- -- 6,391 701

South Carolina 2 2,743 42 -- -- -- -- -- -- -- 1,296 162

Tennessee 9 3,954 36 1,300 15 100 0 0 100 0 4,394 512

Total 18 2,946 6 173,717 5,220 53 47 70 13 17 25,044 2,841

Southwest

Arkansas 10 3,327 39 19,820 239 100 0 0 0 100 188 57

Louisiana 21 1,794 47 290,110 5,853 69 31 76 14 10 6,300 600

New Mexico 4 4,756 32 71,958 314 100 0 79 0 21 -- --

Oklahoma 12 3,571 37 156,737 2,742 100 0 47 9 43 -- --

Texas 29 2,035 46 443,906 11,351 42 58 17 42 41 100 12

Total 35 3,096 5 982,532 20,500 59 41 38 29 33 6,588 669

Western

Arizona 2 2,313 45 -- -- -- -- -- -- -- -- --

California 8 2,703 43 222,276 6,470 100 0 0 0 100 700 150

Idaho 2 6,935 11 -- -- -- -- -- -- -- 639 52

Nevada 4 4,263 35 -- -- -- -- -- -- -- 1,160 162

Oregon 2 5,255 26 6,726 100 100 0 0 0 100 1,736 190

Washington 4 5,637 24 15,203 550 100 0 0 0 100 2,545 257

Total 10 4,517 4 244,206 7,120 100 0 0 0 100 6,780 811

 U.S.Total -- -- -- 3,766,666 74,578 85 15 70 13 17 92,820 11,181

MMcf/d = Million cubic feet per day. LDC = Local distribution company. -- = Not applicable. 

Sources: Normal Heating Degree Days: U.S. Department of Commerce, National Oceanic and Atmospheric 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 Geographic Information System,

LNG Database, as of December 1997.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 133

Table C2. Regional and State Energy Profile Comparison of Annual Average Change, 1990-1995

Population Overall Energy Consumption Natural Gas Consumption

Region / in 1995 Annual 1995 Ranking Annual Energy 1995 Gas to Annual Ratio of

 State (estimated) Change 1995 Change Consumed Total) Change Consumption

Millions Percent Quantity U.S. Percent of Total Quantity (Percent Percent (1996) as a

(trillion Btu) (trillion Btu)

As Percent Ranking Production

U.S. Natural Gas

Central

Colorado 3,823 4.6 1,075 26 3.3 27 289 20 3.8 2.02

Iowa 2,852 0.8 1,067 27 3.3 25 264 24 3.4 0.00

Kansas 2,572 1.1 1,041 31 0.9 36 369 16 4.4 2.21

Missouri 5,359 1.4 1,663 20 2.0 17 281 21 3.0 0.00

Montana 879 2.9 379 42 1.7 16 60 43 4.9 0.85

Nebraska 1,652 1.4 580 36 2.2 23 134 36 3.6 0.01

North Dakota 644 0.3 350 43 2.6 14 48 44 8.3 1.33

South Dakota 732 1.5 236 46 2.8 15 35 45 5.5 0.04

Utah 2,000 4.6 638 35 2.1 26 167 31 3.8 1.79

Wyoming 481 1.8 405 41 0.6 26 104 39 3.0 8.05

Total 20,995 2.1 7,435 6 2.1 24 1,749 6 3.8 1.39

Midwest

Illinois 11,847 1.0 3,804 7 0.8 29 1,100 5 2.2 0.00

Indiana 5,841 1.5 2,592 10 0.7 21 542 11 3.5 0.00

Michigan 9,594 0.9 3,157 9 0.8 31 987 6 3.2 0.26

Minnesota 4,658 1.9 1,622 21 2.2 22 358 17 3.0 0.00

Ohio 11,173 0.8 4,038 3 1.0 23 930 7 3.0 0.13

Wisconsin 5,160 1.6 1,749 19 2.4 22 385 13 3.8 0.00

Total 48,272 1.2 16,963 3 1.1 25 4,302 2 2.9 0.08

Northeast

Connecticut 3,274 -0.1 786 34 0.9 17 136 35 5.3 0.00

Delaware 725 2.5 264 45 2.2 24 63 42 6.1 0.00

Maine 1,243 0.3 513 39 1.3 1 6 48 4.1 0.00

Maryland/DC 5,615 1.2 1,490 23 0.8 16 232 27 1.7 0.00

Massachusetts 6,092 0.4 1,494 22 1.1 25 372 15 6.8 0.00

New Hampshire 1,162 1.4 285 44 0.6 7 20 46 8.8 0.00

New Jersey 7,988 1.0 2,543 11 2.6 24 611 9 8.6 0.00

New York 18,185 0.3 3,913 4 0.6 30 1,172 4 4.1 0.02

Pennsylvania 12,056 0.4 3,886 5 1.2 19 747 8 2.0 0.19

Rhode Island 990 -0.4 235 47 5.1 31 72 40 21.4 0.00

Vermont 589 1.3 150 48 2.6 5 7 47 2.2 0.00

Virginia 6,675 2.2 2,056 15 1.4 12 255 25 6.3 0.21

West Virginia 1,826 0.5 819 33 -0.1 19 157 32 4.8 1.19

Total 66,421 0.7 18,433 1 1.2 21 3,850 3 4.9 0.10

Southeast

Alabama 4,273 1.6 1,933 17 2.3 17 331 18 4.4 1.68

Florida 14,400 3.2 3,519 8 1.9 15 533 12 3.6 0.01

Georgia 7,353 3.9 2,512 12 2.3 15 380 14 2.5 0.00

Kentucky 3,884 1.5 1,770 18 3.6 14 246 26 3.7 0.35

Mississippi 2,716 1.6 1,059 29 1.1 28 296 19 0.5 0.35

North Carolina 7,323 3.1 2,328 13 2.3 9 209 30 4.0 0.00

South Carolina 3,699 1.7 1,401 24 1.9 11 156 33 2.7 0.00

Tennessee 5,320 2.6 1,975 16 1.8 13 265 23 2.8 0.01

Total 48,967 2.7 16,497 4 2.2 15 2,415 5 2.9 0.28

Southwest

Arkansas 2,510 2.0 998 32 3.0 28 277 22 1.6 0.78

Louisiana 4,351 0.9 3,814 6 1.4 47 1,778 3 0.8 3.28

New Mexico 1,713 3.8 575 37 -0.4 38 219 29 -3.3 10.98

Oklahoma 3,301 1.4 1,360 25 0.1 43 580 10 -1.4 2.73

Texas 19,128 3.7 10,512 1 1.3 38 3,943 1 0.4 1.57

Total 31,003 2.9 17,258 2 1.3 39 6,797 1 0.2 2.25

Western

Arizona 4,428 6.1 1,059 28 2.4 12 124 37 1 0.00

California 31,878 1.9 7,577 2 -0.4 26 1,956 2 3 0.15

Idaho 1,189 5.2 456 40 2.9 14 66 41 6 0.00

Nevada 1,603 9.3 537 38 5.7 21 115 38 13 0.00

Oregon 3,204 3.6 1,048 30 0.6 15 152 34 8 0.01

Washington 5,533 3.8 2,159 14 0.3 11 229 28 7 0.00

Total 47,835 2.9 12,836 5 0.3 21 2,642 4 4 0.11

U.S. Total 263,493 1.9 89,422 -- 1.3 24 21,753 -- 3 0.88

-- = Not applicable.

Sources: Natural Gas Production and Consumption: Energy Information Administration (EIA), Form EIA-176, “Annual Report of Natural and

Supplemental Gas Supply and Disposition.” Energy Consumption: EIA, State Energy Data Report, Consumption Estimates 1980-1995

(December 1997). Population: U.S. Department of Commerce, Bureau of the Census.
Energy Information Administration

134 Deliverability on the Interstate Natural Gas Pipeline System

Table C3. Regional and State Natural Gas Customer Market Share Changes, 1990-1996 

Region /

State

1996 Share of the Natural Gas Market Share Change Since 1990 Average Annual Change in Consumption

(percent) (percentage point) (percent)

Resi- Com- Indus- Electric Resi- Com- Indus- Electric Resi- Com- Indus- Electric

dential mercial trial Utilities Other dential mercial trial Utilities Other dential mercial trial Utilities Other

Central

Colorado 36 22 27 2 12 -2 -5 7 -1 1 3.3 0.6 9.6 0.7 6.6

Iowa 32 20 42 1 5 a a 0 0 a 3.7 3.8 4.0 0.7 6.0

Kansas 24 16 30 6 24 3 a -3 -1 1 3.2 0.3 -1.6 -10.8 1.4

Missouri 47 25 24 2 3 -2 a 1 0 a 3.0 3.7 4.8 -6.0 19.7

Montana 36 24 29 1 9 -3 -4 8 a -1 5.0 3.6 12.0 6.2 5.7

Nebraska 37 31 27 2 3 -1 -2 4 -2 a 3.0 1.9 6.9 -10.7 4.3

North Dakota 26 25 16 a 33 -3 -7 3 a 7 5.6 2.9 10.8 16.7 12.6

South Dakota 38 31 19 2 9 -3 -3 -4 1 8 5.7 5.4 3.8 71.0 70.0

Utah 34 18 26 2 19 -3 5 -4 1 2 4.1 11.2 3.2 63.3 9.6

Wyoming 13 10 50 0 27 1 0 22 a -23 2.9 2.8 14.2 4.1 -11.8

Total 33 22 30 2 14 a -1 2 -1 -1 3.5 2.8 4.6 -4.3 2.3

Midwest

Illinois 48 19 29 2 1 1 -2 -1 1 0 3.4 1.5 2.7 25.2 3.0

Indiana 31 15 50 1 2 a a a -1 0 4.3 3.7 4.1 -9.4 6.4

Michigan 39 20 34 3 3 1 -4 2 1 0 3.4 -0.2 3.7 9.9 4.2

Minnesota 39 27 28 1 5 2 a -3 a 1 5.0 4.1 2.6 0.3 8.7

Ohio 40 20 37 0 2 a -1 1 a 0 3.3 2.9 3.8 24.7 7.2

Wisconsin 37 23 37 2 1 a a -2 1 0 4.5 6.0 3.5 28.0 2.8

Total 40 20 35 2 2 1 -1 a a 0 3.7 2.3 3.4 10.3 5.4

Northeast

Connecticut 34 31 25 8 1 -4 1 -1 3 1 2.8 5.5 4.5 b 21.6

Delaware 18 12 26 43 0 0 2 -17 16 0 5.3 8.9 -3.9 17.6 4.2

Maine 17 45 38 a 0 2 6 -8 a a 7.1 7.5 1.3 0.0 0.0

Maryland/DC 45 27 22 4 1 5 9 -9 -5 a 4.0 13.0 -4.2 -18.3 1.4

Massachusetts 32 27 28 13 1 -9 7 11 -9 a 1.2 11.9 15.5 -3.1 9.9

New Hampshire 37 37 26 0 0 -5 2 3 a a 3.1 5.9 7.2 0.0 b

New Jersey 37 25 33 4 1 -3 -2 12 -7 0 4.6 4.5 16.6 -14.8 3.1

New York 36 22 29 13 1 -3 a 17 -13 0 3.1 4.5 21.6 -10.0 8.5

Pennsylvania 38 21 33 1 6 1 2 -3 1 0 2.6 3.6 0.6 18.4 1.5

Rhode Island 23 15 31 30 1 -34 3 17 13 0 1.1 27.8 87.1 b 40.3

Vermont 34 39 27 0 0 3 8 -1 -10 a 2.9 5.6 0.7 b 13.5

Virginia 32 25 35 4 4 3 2 -6 1 0 6.9 6.4 2.0 11.1 3.4

West Virginia 24 18 32 0 25 -3 a -8 a 10 2.4 4.8 0.6 7.4 15.5

Total 35 23 30 8 3 -3 2 6 -5 a 3.3 5.6 8.4 -4.7 6.2

Southeast

Alabama 17 9 62 2 10 -1 -1 2 a a 3.8 3.1 5.7 11.8 5.4

Florida 3 9 28 58 2 -1 -3 2 1 a 4.0 2.4 8.7 9.8 11.1

Georgia 33 16 47 1 2 4 a -5 1 0 6.0 3.7 2.0 78.1 2.5

Kentucky 30 17 40 1 12 -1 a 3 1 -3 3.9 4.3 5.6 47.2 0.5

Mississippi 11 8 30 31 20 1 1 -10 5 2 3.2 4.1 -3.9 8.7 2.8

North Carolina 28 19 49 1 3 6 a -5 0 0 9.2 4.5 3.3 2.3 3.0

South Carolina 20 14 64 1 2 6 2 -3 -5 0 8.3 4.8 1.7 b 1.7

Tennessee 25 21 45 a 9 4 1 -5 a a 7.4 5.2 2.5 14.7 4.1

Total 20 13 44 16 7 2 0 -3 2 a 5.8 4.0 3.2 8.3 3.1

Southwest

Arkansas 17 11 52 13 7 0 1 0 -1 0 3.0 3.8 2.8 1.2 1.5

Louisiana 3 2 63 15 17 a a 5 -2 -3 1.0 0.6 2.4 -1.3 -2.2

New Mexico 15 12 10 14 49 3 2 2 3 -10 3.2 1.9 2.9 2.9 -4.9

Oklahoma 14 8 35 24 19 3 2 3 -4 -4 2.8 3.8 0.5 -3.8 -4.6

Texas 6 4 54 26 10 a a 6 -2 -4 1.4 0.5 3.9 0.6 -4.2

Total 7 5 53 22 14 a a 6 -2 -4 1.9 1.4 3.2 -0.1 -3.6

Western

Arizona 23 24 22 16 14 0 1 8 -3 -6 -0.4 0.4 6.9 -5.1 -6.9

California 26 13 38 18 5 -1 -2 8 -7 2 -1.5 -3.6 3.6 -7.4 24.6

Idaho 22 17 52 a 9 3 -2 a a -2 10.3 5.4 6.9 0.0 2.9

Nevada 18 17 26 38 1 -8 -7 15 0 a 4.9 5.3 37.1 13.1 -5.2

Oregon 20 15 52 8 8 -2 -4 7 2 -4 6.7 4.2 10.5 13.4 -3.0

Washington 26 20 48 3 3 1 -4 0 3 0 8.1 3.9 6.7 b 5.6

Total 25 15 39 16 5 -2 -2 8 -6 1 0.0 -1.2 5.0 -4.6 9.6

Total U.S. 24 15 41 13 8 1 a 3 -2 -1 3.0 2.8 4.0 -0.4 -0.5

aBetween plus 0.5 percent and minus 0.5 percent.

bOver plus or minus 100 percent per annum. Result very large (small) due to large fluctuations in annual volumes reported in this category.

Note: Totals may not equal sum of components because of independent rounding.

Source: Energy Information Administration, Form EIA-176, “Annual Report of Natural and Supplemental Gas Supply and Disposition.”
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 135

Table C4. Regional and State Natural Gas Customers, Average Annual Growth, 1990-1996

Residential Customers Commercial Firms Industrial Firms Electric Utilities

Annual Change Annual Change Annual Change Annual Change

(percent) (percent) (percent) (percent)

1

Region 1996 of Users Use 1996 of Users Use 1996 of Users Use Units Units Capacity Capacity

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

In In

Number Number

Central

Colorado 1,147,743 2.6 0.6 121,221 1.2 -0.6 2,099 13.8 -3.4 -1.3 -0.8 0.5 1.3

Iowa 771,109 1.5 2.1 89,663 1.3 2.4 2,066 1.6 2.4 -2.8- -5.0 -15.3 -9.4

Kansas 804,213 1.2 1.9 89,168 0.7 -0.4 2,988 -6.6 7.7 -1.3 -1.1 0.2 -0.5

Missouri 1,275,465 0.8 2.0 133,445 4.1 -0.6 3,408 1.5 3.3 0.3 0.3 0.9 7.2

Montana 205,199 2.8 2.0 26,374 2.1 1.3 466 0.3 11.6 -1.1 0.0 0.1 0.0

Nebraska 439,931 1.3 1.6 61,117 0.2 1.6 2,234 36.0 -23.4 -0.9 1.2 0.6 2.3

North Dakota 97,761 2.2 3.2 13,789 1.3 1.6 206 3.8 6.6 -2.8 0.0 -1.2 0.0

South Dakota 127,269 3.3 2.3 16,880 4.0 1.3 444 8.4 -4.9 -6.1 1.1 1.7 30.9

Utah 562,343 3.7 0.2 40,107 2.5 8.4 923 -11.1 23.0 2.1 4.6 0.4 -2.2

Wyoming 131,910 2.6 0.3 17,036 3.7 -1.0 170 -9.9 25.6 1.6 33.3 0.5 18.7

Total 5,562,943 1.8 1.5 608,800 1.9 0.8 15,004 1.5 3.2 -1.3 -1.0 -0.5 1.2

Midwest

Illinois 3,494,545 1.0 2.3 265,007 0.5 1.0 29,493 2.2 0.5 -2.3 -1.1 0.2 14.0

Indiana 1,489,647 1.9 2.3 139,097 1.8 1.8 6,586 0.4 3.7 0.5 1.2 0.1 1.0

Michigan 2,812,876 1.5 1.9 214,843 1.6 -1.8 11,848 0.5 3.2 -0.6 4.3 -0.2 22.3

Minnesota 1,103,709 2.6 2.3 105,531 1.7 2.3 2,564 -0.1 2.7 -0.4 -2.6 0.7 -15.8

Ohio 2,994,891 1.3 2.0 259,663 1.8 1.1 8,672 0.7 3.0 0.1 2.1 0.2 10.5

Wisconsin 1,324,570 2.8 1.6 129,146 3.3 2.6 5,861 -3.6 7.3 -0.1 2.3 2.0 20.7

Total 13,220,238 1.6 2.0 1,113,287 1.6 0.7 65,024 0.8 2.6 -0.6 0.3 0.3 8.0

Northeast

Connecticut 433,778 0.2 2.6 47,055 0.6 4.9 3,435 2.4 1.4 -2.8 30.6 -2.1 11.7

Delaware 106,548 3.1 2.1 9,518 4.1 4.6 250 0.7 -4.6 -0.6 4.9 2.3 4.3

Maine 14,982 3.8 3.1 6,414 7.1 0.2 87 1.8 0.0 -0.2 0.0 -0.1 0.0

Maryland/DC 1,006,227 1.7 2.3 80,943 3.3 5.9 430 -167.6 125.7 -1.4 6.7 1.8 6.9

Massachusett 1,188,317 1.0 0.2 105,889 0.9 11.6 10,952 11.5 8.2 -1.3 -0.5 -1.6 9.1

New Hampsh. 75,175 2.4 0.6 12,755 3.3 2.5 367 0.2 7.2 -3.1 16.7 -0.9 34.6

New Jersey 2,147,622 1.3 3.1 224,749 0.5 4.0 10,139 10.8 4.8 -2.5 0.0 0.1 1.8

New York 4,048,166 0.6 2.5 315,855 2.0 2.5 15,300 -9.7 33.3 -2.0 -1.4 -0.5 3.6

Pennsylvania 2,431,909 0.8 1.7 214,340 2.3 1.2 6,441 0.5 -0.1 -1.0 3.4 4.0 41.3

Rhode Island 204,259 0.8 0.3 21,664 3.5 23.6 363 -33.6 118.7 -8.8 -25.0 20.2 37.1

Vermont 24,383 4.9 -2.2 3,790 4.3 1.3 27 11.2 -10.3 1.5 -- 0.4 1.1

Virginia 789,985 4.0 2.7 77,284 3.3 3.1 2,822 28.2 -25.9 3.0 -0.8 1.4 -10.8

West Virginia 358,049 0.4 2.0 33,837 0.5 4.3 182 0.0 0.9 -3.2 -- 0.0 --

Total 12,829,400 1.1 2.1 1,154,093 1.8 3.8 50,795 -1.5 9.7 -1.1 0.4 0.1 4.4

Southeast

Alabama 766,322 1.9 1.9 62,064 1.5 1.6 2,512 0.6 5.1 1.1 10.8 0.6 6.5

Florida 521,674 2.2 1.7 47,578 1.5 0.9 517 2.2 6.1 -0.2 2.0 2.1 1.7

Georgia 1,538,458 2.4 3.4 123,200 2.2 1.4 3,310 0.8 1.1 0.3 8.7 1.6 19.5

Kentucky 696,989 1.8 1.9 76,079 2.1 2.2 1,633 0.9 4.6 0.2 5.1 0.1 24.5

Mississippi 418,442 1.5 1.7 46,029 1.1 3.0 1,241 -1.0 -2.9 0.3 0.4 0.4 2.6

North Carolina 699,159 5.1 3.9 93,504 5.5 -1.0 3,973 6.6 -3.1 -1.2 8.9 0.6 23.8

South 426,088 3.9 4.1 48,650 3.4 1.4 1,759 4.3 -2.6 1.5 2.2 2.6 1.3

Tennessee 841,232 5.0 2.2 103,867 2.7 2.4 2,306 -0.4 2.9 -0.7 -- 0.3 -2.0

 Total 5,908,364 2.9 2.7 600,971 2.6 1.3 17,251 1.9 1.4 0.1 3.2 1.2 4.2

Southwest

Arkansas 539,952 1.7 1.2 67,293 1.5 2.2 1,486 1.1 1.8 0.2 -2.4 0.0 -0.1

Louisiana 945,967 0.2 0.8 62,101 -0.2 0.7 1,444 -1.0 3.7 -0.1 0.2 0.4 1.4

New Mexico 428,621 2.5 0.6 37,796 -0.1 2.0 1,365 -33.1 29.4 0.6 2.3 0.1 31.4

Oklahoma 866,531 1.0 1.7 89,852 0.8 3.0 2,843 -0.3 0.8 0.2 0.3 0.4 2.5

Texas 3,501,853 1.3 0.0 329,287 3.5 -3.3 8,796 -14.2 18.1 -0.2 -0.4 0.7 0.5

Total 6,282,924 1.2 0.6 586,329 2.2 -0.9 15,934 -7.8 11.0 0.1 -0.1 0.5 1.4

Western

Arizona 689,597 2.8 -3.3 49,693 0.9 -0.6 534 0.3 6.6 1.0 0.3 0.3 0.9

California 8,969,308 0.9 -2.4 408,294 -0.3 -3.3 36,613 -4.0 7.5 0.5 0.8 0.2 -0.3

Idaho 187,756 8.7 1.0 25,271 4.5 0.7 183 22.9 -15.6 -0.9 -- 1.9 --

Nevada 393,783 7.5 -2.7 26,613 4.3 0.9 121 3.3 32.7 1.1 5.6 2.3 3.0

Oregon 433,638 5.0 1.5 57,613 3.5 0.6 799 2.4 8.2 0.2 2.1 -1.2 5.6

Washington 673,357 6.6 1.0 73,708 4.0 -0.3 3,587 0.8 5.9 -0.1 -4.2 -1.1 -1.0

Total 11,347,439 1.7 -1.7 641,192 0.9 -2.1 41,837 -3.4 8.4 0.3 0.9 0.1 0.3

Total U.S. 55,151,308 1.6 1.4 4,704,672 1.8 1.0 205,847 -1.0 5.1 -0.5 0.3 0.3 2.5

Includes both primary and secondary generating units. 1

-- = Not applicable.

Source: Natural Gas Usage: Energy Information Administration (EIA), Form EIA-176, “Annual Report of Natural and Supplemental Gas Supply

and Disposition.” Electric Generation Capacity: EIA, Form EIA-860, “Annual Electric Generation Report,” 1990 through 1996.
Energy Information Administration

136 Deliverability on the Interstate Natural Gas Pipeline System
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 137

Appendix D

Data Sources

The data presented in the body of this report came from many measure is likely to be sustainable for more than a short

sources and often required some adjustment to provide period of time.

information on a comparable basis for use in the analysis.

This appendix provides detailed information on the Information on capacity levels for the interstate pipeline

methodology and source material used to develop estimates systems is generally available from filings at the Federal

of interstate pipeline capacity at State borders and the changes Energy Regulatory Commission (FERC). However, this

in energy usage patterns from 1990 through 1995. information is typically associated with compressor stations

The following is a list of the data sources discussed in this State-to-State capacities on the pipelines, an approach was

appendix. required. Further, while there is a regulatory requirement for

 Annual pipeline company reports filed with the Federal provided in the submissions sometimes is unclear as to

Energy Regulatory Commission (FERC) under 18 CFR whether the data provided by a company are in fact the

§284.12, “Peak-Day Capacity Report,” and §260.8, information requested.

Format FERC 567, “System Flow Diagrams.”

 FERC Form 2, “Annual Report of Major Natural Gas done by the Energy Information Administration during 1991

Companies” and 1992, using 1990 as the base year. The initial approach

 FERC Form 11, “Natural Gas Pipeline Monthly following:

Statement,” 1995 and earlier years. (The survey became

a quarterly report in 1996.)  Develop initial capacity estimates by using compressor

 FERC Index of Customers Diagrams."

 Energy Information Administration (EIA), Form  Adjust initial estimates by using delivery requirements of

EIA-176, “Annual Report of Natural and Supplemental customers located between the State line and the station

Gas Supply and Disposition” and for any contracted receipts from other pipelines.

 Energy Information Administration, Form EIA-191,  When compressor station data were unavailable on

“Underground Natural Gas Storage Report” Format 567, derive a statistical estimate by using a

 Natural Gas Annual, DOE/EIA-0130, various issues. pipeline segment in question. 

Pipeline Capacity

The measure of pipeline capacity that was estimated and

addressed in this report is the daily capacity of the interstate

natural gas pipeline network at regional and State boundaries.

Specifically, it is an estimate of the maximum volume of gas

that can be transported under normal operating conditions for

a sustained period of time. While pipeline systems have

considerable operational flexibility to increase deliveries of

natural gas above design capacity levels to certain areas for

short periods of time, this often means that deliveries are

reduced elsewhere or that line packing occurs. Neither

and not State border capacity. Thus, to estimate the

the submission of design information, the terminology

The original compilation of pipeline capacity estimates was

taken to derive the State-to-State capacity information was the

station data from FERC Format 567, "System Flow

regression equation based upon the diameter(s) of the

 Impute remaining missing values by using proxies for

capacity. Data used for this purpose include contract

demand (CD) data for pipeline sales customers, which

were available for the years 1988 and 1989. (CD data

were no longer available once FERC Order 636 was

implemented in November 1993.)

 Cross check the State border capacities for reasonableness by using contract demand levels (if not used as a

proxy for capacity); flow data from Form EIA-176,

“Annual Report of Natural and Supplemental Gas Supply

and Disposition”; and consultations with FERC staff and

company officials. 
Energy Information Administration

138 Deliverability on the Interstate Natural Gas Pipeline System

The initial (1990) estimates of capacity on a pipeline segment annual FERC Format 567 “System Flow Diagram” for each

at a State border were based on reported compressor station pipeline system were compared with the previous year’s

throughput, the daily output of whichever compressor station submission. The primary items examined were the throughput

appeared to be closest to the State border. The working capabilities of the pipeline’s compressor stations and whether

assumption was that throughput capability, even if only an they had increased, had changed, or had new stations added.

estimated flow under current operating conditions, of any In addition, comparisons of receipt and delivery point

compressor station is a reasonably good estimate of volumes were also performed to determine changes in peakpeak-period throughput at that point on the line. (Note: day deliverabilities and as a replacement for contract demand

Compressor station output may be a “constraint” on data which were no longer current. Available data on pipeline

throughput when downstream pipeline diameter and other construction projects completed during the interim were also

characteristics of the segment may allow the physical pipeline factored into any estimate adjustments. These comparisons

to handle greater loads than required under current customer were done, to the extent possible, through comparative

peak-day commitments. Conversely, the designed compressor analyses of updated databases. Initial estimates of revised

output may be greater than can be sent through existing capacity levels were produced and displayed on annotated

pipeline configurations.) pipeline maps.

When no delivery or receipt points were between the selected These estimates were then presented to the pipeline company

compressor station and the State line, the capacity at the State or FERC staff for evaluation. These inputs were used to settle

border was assumed to equal the station capability, even upon a final estimate.

though some friction losses would occur because of the

distance between the line and compressor. When data were

available for both receipt and CD deliveries between the

compressor station and the State line, then the initial capacity

estimates were adjusted to account for these volumes.

In some cases, peak-day information rather than design

capacity was reported on the Format 567. These estimates

were considered a reasonable proxy for capacity.

Under certain conditions, contract demand data were used to

estimate capacity levels at a State border. CD data were

assumed to be a reasonable reflection of current peak-day

demands on the pipeline system and, therefore, a close

approximation of the capability or capacity of the pipeline to

supply those customers. A pipeline's CD commitment levels

within a State were used as a surrogate for a measure of that

pipelines' capacity into the State when the pipeline system, or

a branch, terminated in the State. Even in this instance,

however, the pipeline company could meet a portion of its

commitments from sources within the State borders.

In some cases, compressor station data and contract demand

data were inadequate to develop an initial capacity estimate,

and other methods were pursued to make the initial capacity

estimate. For instance, regression equations to estimate

capacity were developed by use of a universe of 814

compressor stations with known pipeline diameters,

capacities, and pressures, extracted from the Format 567

filings. The results indicated that diameter alone was a good

predictor of capacity in these equations.

Subsequently, updated annual capacity estimates were

developed for years 1991 through 1996 by using the 1990

levels as starting points. First, the contents of the most recent

Average Daily Pipeline Flow

The data source for actual average daily pipeline volume

flows across 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, consumption, and transportation volumes

presented in this report.

The respondent universe of the Form EIA-176 includes

interstate and intrastate pipeline companies; investor and

municipally owned natural gas distributors; underground

natural gas storage operators; synthetic natural gas plant

operators; and field, well, or processing plant operators that

deliver natural gas directly to consumers and/or transport gas

to, across, or from a State border through field or gathering

lines.

The average daily flow volumes presented in the “Region-toRegion Capacity” tables in the report are based upon

preliminary 1996 data from Form EIA-176. They are the sum

of data that can be identified as volumes brought across a

border: on-system purchases received at a State border, plus

transportation and/or exchange receipts received at a State

line, plus transported into the report State. The data on Form

EIA-176 are annual; average daily levels were computed on

a 366-day basis (1996 was a leap year).

Greater detail concerning Form EIA-176, its background, and

EIA processing methodology, may be found in the EIA

publication Natural Gas Annual 1996, DOE/EIA-0131,

Appendix A.
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 139

System Flow Rate Data

The pipeline systemwide flow rate data discussed 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

December 1995 are maintained and available on computer

tape.

Transportation, sales, and intercompany transfer throughput

volumes are reported, but for the total pipeline system only.

As a result, these data cannot be used to compute regional or

State-level utilization levels. However, the historical data

were used to identify and quantify the largest monthly

throughput level occurring on the individual pipeline systems

over the period 1980 through 1995. Average monthly

throughput rates for 1989 and 1995 were then divided by the

largest monthly throughput (which was used as an

approximation of a 100-percent load factor or a surrogate

measure for full capacity utilization) to estimate the overall

relative flow rate (throughput) on the various pipeline systems

in 1995.

This report also uses data from the FERC Form 2, “Annual

Report of Major Natural Gas Companies,” for discussions

pertaining to system peak-day deliverability rates and

utilization levels on those days. These data, which are

reported on page 518, “Transmission System Peak Deliveries”

of FERC Form 2, provide peak delivery volumes at several

levels. Those periods are: highest day, 2 highest, and nd

3 highest days deliveries, highest 3 consecutive days, and rd

highest month deliveries. These data are to be reported for the

period “during the twelve months embracing the heating

season overlapping the year’s end for which this report is

submitted.” The latest such period available for this report

was the 1995-96 heating year (April 1995 through March

1996). The FERC Index of Customers filing was the principal source

The peak-day (highest one day) deliveries reported on FERC Chapter 5. The guiding principal for the analysis was to

Form 2 were used in relation to system capacity levels assemble the most recent, reliable information available.

reported on the annual pipeline company reports filed with the Therefore, the quarterly FERC Index of Customers filings for

FERC under 18 CFR §260.8. The comparison 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 companies were excluded from the

pipeline usage during periods of highest user need and some filed Index of Customers because their data were inconsistent

indication of how well the system is able to meet its or missing. The resulting sample consists of 63 interstate

obligations to its customers under current capacity limitations. pipeline companies. Since the analysis was not concerned

Transportation System Access

The analysis of transportation system access (Chapter 5)

employed a sample of 46 major interstate natural gas pipeline

companies. The sample was selected to ensure that adequate

and uniform peak-day and monthly transportation information

was available for each pipeline company. All pipeline

companies in the sample were required to have at least three

of the four peak-delivery data necessary to determine

maximum capability. The data used in the derivation of

maximum capability are from the pipeline company reports

filed with the Federal Energy Regulatory Commission

(FERC). These data include: the estimated peak-day capacity

of the pipeline company’s system from the 1996 Peak-Day

Capacity Report (18 CFR §284.12); the quarterly contracted

firm transportation capacity from the quarterly Index of

Customers filings for the period April 1, 1996, through April

1, 1997; the coincident 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 sufficient information to

estimate maximum capability, the analysis required that each

pipeline company in the sample had filed FERC Form 11,

“Natural Gas Pipeline Company Quarterly Statement of

Monthly Data,” for the period April 1996 through March

1997. The transportation volumes from FERC Form 11 were

used to assess the utilization of the reserved capacity. 

These data requirements resulted in a sample size that was

17 pipeline companies smaller than the sample selected for

the analysis of firm capacity contracts, also in Chapter 5.

Although the accessibility analysis used 32 percent fewer

pipeline companies than the sample for the contract analysis,

it excluded only 1 percent, or 1.4 quadrillion Btu per day, of

the firm contracted capacity (based on the April 1, 1997,

FERC Index of Customer filing) included in the firm contract

analysis.

Firm Capacity Contracts

of information for the analysis of firm capacity contracts in

with consistency across several sources of information, it

employed a much larger sample of pipeline companies than

the accessability analysis.

Firm transportation capacity was examined by type of

shipper. Pipeline companies are required to disclose the

amount of capacity reserved by each firm customer in the
Energy Information Administration

140 Deliverability on the Interstate Natural Gas Pipeline System

quarterly Index of Customers filing to the Federal Energy

Regulatory Commission. The Index of Customers provides

the name of each company that contracted for firm

transportation, but it does not provide any other information

to identify what type of company each shipper was. Thus,

EIA staff compared shipper names with lists of companies

from other sources to classify each shipper. Four sources were

used for comparison: (1) Form EIA-176, “Annual Report of

Natural and Supplemental Gas Supply and Disposition”; (2)

Benjamin Schlesinger and Associates, Inc., Directory of

Natural Gas Marketing Service Companies, Eleventh Edition

(May 1997) (a proprietary source); (3) Energy Planning, Inc.,

Directory of Natural Gas Consumers, 5th Edition (1996) (a

proprietary source); and (4) Form EIA-860, “Annual Electric

Generator Report.”

The list of electric utilities from Form EIA-860 included

combination electric and gas utilities. Shippers that appeared

in this list and that used natural gas as either the primary or

alternative source of fuel for electricity generation were

classified as electric utilities, even the combination

companies. Combination companies that did not use natural

gas as the primary or alternative source of fuel for electricity

generation were classified as local distribution companies. For

example, Baltimore Gas and Electric Company was classified

as an electric utility while Atlanta Gas Light Company was

classified as a local distribution company.

The final set of shipper categories is as follows:

 Electric utilities (including combination electric and

natural gas utilities for which natural gas is the primary

or alternative source of fuel for generating electricity)

 Industrial companies (including independent power

producers, cogenerators, and commercial firms)

 Local distribution companies (including intrastate

pipeline companies and combination electric and natural

gas utilities for which natural gas is not the primary or

alternative source of fuel for generating electricity)

 Marketers

 Interstate pipeline companies

 Other companies (including producers and gatherers and

companies that could not otherwise be classified).

Underground Natural Gas Storage

Data

Each month, on the Energy Information Administration’s

Form EIA-191, “Underground Natural Gas Storage Report,”

U.S. storage operators are required to report their current

estimates of injections and withdrawals occurring in the

previous month at each site they operate. In addition, on an

annual basis, each operator is expected to report any change

to total, base, or working gas capacity, as well as daily

deliverability (see Glossary) that may have occurred at the

site during the previous calendar year.

These data have been compiled in a database with each site

identified by such criteria as ownership type (interstate

pipeline, local distribution company, or independent

operator), type of facility (depleted reservoir, salt cavern,

aquifer, or mine), and interconnecting pipeline. The

combination of this information, in association with the

capability (capacity level) of connecting pipeline systems,

with an approximate location, permitted an analysis and a way

of estimating the impact of storage availability and

operational capability on service to producers and shippers

and pipeline utilization.

Maps and Mapped Data

The geographic displays in this report were produced, in

whole or in part, using the EIAGIS-NG Geographic

Information System. The system consists of a series of sitespecific databases and digitized pipeline maps residing in a

personal computer (PC) environment. The pipeline map files

were developed from publicly available sources, although in

some cases, more detailed maps were provided by the

individual pipeline companies. Currently, the EIAGIS-NG

contains map data for 61 interstate and 71 intrastate pipeline

companies located in the United States, and 18 interstate

pipeline companies located in Canada.

Many of the interstate pipeline map files also contain profile

(attribute) data for each pipeline segment, such as pipe

diameter, maximum allowable pressure, looping, etc. These

data were compiled from the pipeline system schematic

contained in the Form FERC-576, “System Flow Diagram.”

The individual databases supporting the system include the

following pipeline-related data:
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Deliverability on the Interstate Natural Gas Pipeline System 141

 Compressor stations

 Delivery points

 Receipt points

 Major interconnections

 State border crossings and capacity levels.

Nonpipeline-related databases include:

 Underground storage sites

 Planned underground storage projects

 Proposed construction projects

 Local distribution company service areas

 Export and imports

 Market centers/hubs

 Electric power plants, etc.

The principal geographic data used in this report to compile

capacity estimates were the pipeline maps and their receipt,

delivery, interconnection, and compression 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 Statistics. The groupings are as follows:

Northeast Region – Federal Region 1: Connecticut, Maine,

Massachusetts, New Hampshire, Rhode Island, and Vermont.

Federal Region 2: New Jersey, and New York. Federal

Region 3: Delaware, District of Columbia, Maryland,

Pennsylvania, Virginia, and West Virginia.

Southeast Region – Federal Region 4: Alabama, Florida,

Georgia, Kentucky, Mississippi, North Carolina, South

Carolina, and Tennessee.

Midwest Region – Federal Region 5: Illinois, Indiana,

Michigan, Minnesota, Ohio, and Wisconsin.

Southwest Region – Federal Region 6: Arkansas, Louisiana,

New Mexico, 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.
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Deliverability on the Interstate Natural Gas Pipeline System 143

Glossary

Abandonment: Regulatory permission to discontinue application for the Certificate of Public Convenience and

service by removing various facilities from the transmission Necessity at the Federal Energy Regulatory Commission.

and distribution system or to stop transporting gas to or for Generally, the certificated capacity represents a minimum level

specific customers or to certain areas. For instance, to of service that can be maintained over an extended period of

discontinue storage services, well production, or gathering time and does not always represent the maximum throughput

systems. capability of the system on any given day.

Affiliated Company: A company that is either directly or Citygate: Location where gas is delivered to a local distribution

indirectly controlled and/or owned by another firm or company by a pipeline transmission company.

holding company.

Alternate Receipt and Delivery Points: Locations other gas), in conjunction with industrial operations or other nonthan the primary points specified in a contract at which a utility gas-burning functions, which is used to power generators

shipper can schedule delivery on a firm basis. for the secondary production of electricity. 

Alternative Fuel Capacity: The on-site availability of Coincidental Peak-Day Flow: The volume of gas that moves

apparatus to burn fuels other than natural gas. through a pipeline or section thereof or is delivered to a

Associated-Dissolved Gas: Natural gas produced in handles the largest volume of gas.

association with oil, also known as casinghead gas.

Baseload: A volume of gas that serves as a constant load electricity by use of a gas turbine or a heat recovery boiler and

over a period of time. a steam turbine in tandem.

Blanket Certificate (Authority): Permission granted by Commercial Service: Natural gas service to restaurants, retail

the Federal Energy Regulatory Commission (FERC) for a stores, schools, institutions, etc.

certificate holder to engage in an activity (such as

transportation service) on a self-implementing or prior Compressor Station: An installation located on a pipeline

notice basis, as appropriate, without case-by-case approval system and which contains engine- or turbine-driven

from FERC. compressors used to move natural gas through a pipeline by

Btu: Abbreviation for British thermal unit. The quantity of of the station are defined primarily by level of installed

heat needed to raise the temperature of 1 pound of water by horsepower and designed daily gas throughput capacity. 

1 degree Fahrenheit at a specified temperature and pressure 

(from 59 degrees Fahrenheit to 60 degrees Fahrenheit at an Contract Demand: The level of firm service in terms of the

atmospheric pressure of 29.92 inches of mercury). maximum daily and/or annual volumes of natural gas sold

Capacity Release Market: Where natural gas shippers may the contract. Failure of a pipeline company to provide service

offer the rights of some or all of their firm capacity in at the level of the contract demand specified in the contract can

exchange for revenue credits. result in a liability for the pipeline company.

Capacity Turnback: When natural gas shippers, upon Cushion (Base) Gas: The volume of gas, including native gas,

expiration of their contract(s) for pipeline capacity do not needed as a permanent inventory in a storage reservoir in order

renew capacity rights, in whole or in part, with the original to maintain adequate reservoir pressure and deliverability rates.

pipeline. 

Certificated Capacity: The capability of a pipeline project section of pipe determined by dividing the total annual volume

to move gas volumes on a given day, based on a specific set of gas that moves through a section of pipe by 365 days.

of flowing parameters (operating pressures, temperature, Volumes are expressed in million cubic feet per day measured

efficiency, and fluid properties) for the pipeline system as at a pressure of 14.73 psia and a temperature of 60 degrees

stated in the dockets filed (and subsequently certified) in the Fahrenheit. For pipes that operate with bidirectional flow, the

Cogeneration: The production of steam (usually by natural

customer on the day of the year when the pipeline system

Combined-Cycle Generation: System for generating

raising the pressure applied to the flow of gas. The capabilities

and/or moved by the pipeline company to the customer holding

Daily Average Flow: The volume of gas that moves through a
Energy Information Administration

144 Deliverability on the Interstate Natural Gas Pipeline System

volume used in computing the average daily flow rate is the only a specified part of the year as in off-peak service. Certain

volume associated with the direction of flowing gas on the firm service contracts may contain clauses that permit

peak day. unexpected interruption in case the supply to residential

Deliverability: Refers to the volumes of natural gas that

may be transferred at a designated point on the Gathering System: A network of small pipelines which

transportation network. The specific volume level is connect producing wells with a transmission system.

normally stated on a peak-day capability basis and is a

function of facility (system) design, which itself is premised Gas Turbine: Power equipment of the turbine type which

upon actual or estimated market demand requirements. utilizes the gas combustion as a motive force.

Pipeline network deliverability in this analysis is predicated

upon a summary measure of pipeline capacity at regional Grid (Transmission) System: Natural gas pipeline system

and/or State boundaries. Pipeline capacity is, in part, a characterized by a large number of laterals or branches from the

function of the number of pipes, their diameter, mainline that tend to form a network of integrated receipt,

compression, and operating pressure situated at the transfer delivery, and pipeline interconnections operating in and serving

point. Deliverability from storage represents a volume level major market areas. Similar to a local distribution company

that may be transferred to the pipeline network on a peak (LDC) network configuration but on a much larger scale.

day to supplement the pipeline capacity serving the regional

market. Heating Degree Day: An index indicating the difference

Deliverability (from storage): The output of gas from a a day, where the average temperature is the average of the day's

storage reservoir, as expressed as a rate in thousand cubic high and low temperatures. If a day's average temperature were

feet (Mcf) per 24 hours, at a given total volume of gas in 45, there would be 20 degree days for the date. If the average

storage with a corresponding reservoir pressure and at a temperature were above 65 degrees Fahrenheit, then the heating

given flowing pressure at the wellhead. degree day would equal zero.

Design Capacity: See certificated capacity. The design Industrial Service: Natural gas service to factories, mines, pulp

capacity of pipeline sections having bidirectional flow is the mills, smelters, etc.

capacity associated with the direction of the flow observed

on the peak day. Infill Drilling: There are two types of infill drilling: (1) The

Design Day: A 24-hour period of demand which is used as increase total ultimate recovery; and (2) drilling a replacement

a basis for planning gas capacity and service requirements. well within a proration unit, after the original well has been

Downstream Pipeline (State): A pipeline (State) closer to could not be reached or drained by recompletion.

the market area, as opposed to an upstream one, which is

closer to the production area. Interruptible Service: A sales volume or pipeline capacity

Federal Energy Regulatory Commission (FERC): The "Service on an interruptible basis" means that the capacity used

Federal agency with jurisdiction over natural gas pricing, to provide the service is subject to a prior claim by another

wholesale electric rates, hydroelectric licensing, oil pipeline customer or another class of service (18 CFR 284.9(a)(3)). Gas

rates, and gas pipeline certification. utilities may curtail service to their customers who have

Enhanced Oil Recovery: Use of steam injection, most supply or transmission plant capacity without incurring a

often produced by burning natural gas as a secondary or liability.

tertiary oil recovery method. Electricity cogeneration is

usually a by-product of such operations. Interstate Pipeline: A natural gas pipeline company that is

Extraction Plant: A processing plant that is used for the State boundaries, and is subject to the jurisdiction of FERC

separation of liquid hydrocarbons from a natural gas stream. under the Natural Gas Act.

Firm Service: Service offered to customers (regardless of Intrastate Pipeline: A natural gas pipeline company engaged

class of service) under schedules or contracts which in the transportation, by pipeline, of natural gas not subject to

anticipate no interruptions. The period of service may be for the jurisdiction of FERC under the Natural Gas Act.

customers is threatened during an emergency.

between 65 degrees Fahrenheit and the average temperature for

drilling of additional wells in a developed field in an effort to

plugged and abandoned, in order to enter a new reservoir that

made available to a customer without a guarantee for delivery.

interruptible service contracts to adjust to seasonal shortfalls in

engaged in the transportation, by pipeline, of natural gas across
Energy Information Administration

Deliverability on the Interstate Natural Gas Pipeline System 145

Lateral: A section of natural gas pipeline that branches off Native Gas: The volume of gas remaining in a reservoir after

from the mainline to connect with or serve a specific economic production ceases and before conversion to use as a

customer or group of customers. storage site.

LDC: Local Distribution Company. A natural gas utility NGPA Section 7 Authority: Section 7 of the Natural Gas Act

company which receives gas from a mainline transmission of 1938 requires an interstate pipeline company to justify and

pipeline company and distributes same to the ultimate acquire a certificate of public need and convenience before

consumer. constructing facilities to transport gas. Pipeline companies may

Line Packing: Increasing the amount of gas in the system transportation service, subject to certain conditions and

or pipeline segment by temporarily increasing pressure to reporting requirements.

meet high demand for a short period of time. Often

exercised overnight as a temporary storage medium to meet NGPA Section 311: Section 311 of the Natural Gas Policy Act

anticipated next-day peaking demands. of 1978 allows an interstate pipeline company to transport gas

Liquefied Natural Gas (LNG): Natural gas that has been company. Pipeline companies may expand or construct facilities

subjected to high pressure and very low temperatures and used solely to enable this transportation service, subject to

stored in a liquid state. It is returned to a gaseous state by certain conditions and reporting requirements.

the reverse process and used as a peaking fuel.

Load Balancing: Maintaining system integrity through Order 636 that allows customers to receive gas on demand to

measures which equalize pipeline (shipper) receipt volumes meet peak service needs subject to delivering supplies into the

with delivery volumes during periods of high system usage. pipeline under a pack or draft order and without paying daily

Withdrawal and injection operations into underground balancing and scheduling penalties.

storage facilities are often used to balance load on a shortterm basis. Nonassociated Gas: Natural gas produced from gas wells that

Load Factor: The ratio of average daily deliveries to

peak-day deliveries over a given time period. Noncoincidental Peak-Day Flow: The largest volume of gas

Looping: Increasing capacity on a pipeline system or single day during the year.

segment by adding another pipeline running parallel to

existing lines. Off-Peak Period: Period of low contract demand, such as

Mainline (Transmission Line): The wide-diameter, often- apply to periods as short as certain periods of a day when usage

times long-distance portion of a natural gas pipeline system, is low.

excluding laterals, located between the gathering system

(production area) or gas-processing plant and other receipt Off-Peak Service: Service made available on special schedules

points and the principal customer service area(s). or contracts, but only for a specified part of the year during the

Market Center/Hub: A transfer site or system where

several interstate and/or intrastate natural gas pipelines Open-Access Transportation: The contract carriage delivery

interconnect and where shippers may obtain services to of nonsystem supply gas on a nondiscriminatory basis for a fee.

manage and facilitate their routing of supplies from Generally subject to transportation tariffs, which are usually on

production areas to markets. Title transfer, temporary an interruptible service basis on first-come, first-serve capacity

storage, and imbalance management are some of the usage.

services usually available at such facilities.

Marketed Production: Gross withdrawals from gas/oil to accept bids from shippers and others for potential new

wells less gas used for repressuring, quantities vented and transportation capacity. Bidders may or may not have to provide

flared, and nonhydrocarbon gases removed in treating or “earnest” money, depending upon the type of open season. If

processing operations. enough interest is shown in the announced new capacity, the

expand or construct facilities used solely to enable this

“on behalf of” any intrastate pipeline or local distribution

No-notice Service: A bundled, citygate firm service under

do not contain or produce oil.

delivered to a particular customer by a pipeline company in a

during the summer months in northern climates but may also

off-peak periods.

Open Season: A period (often 1 month) when a pipeline offers

pipeline will refine the proposal and prepare an application for
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146 Deliverability on the Interstate Natural Gas Pipeline System

construction before the appropriate regulatory body for Spot Market: A market for the buying and selling of short-term

approval. natural gas contracts, often for 30 days or less (although

Operator: The person or firm responsible for the short-term), usually on an interruptible or best-efforts basis.

day-to-day operation of a plant or facility.

Optional Certificate (formerly known as Optional volume of gas an underground storage reservoir can store,

Expedited Certificate (OEC)): In 1987, FERC issued limited by such factors as facilities, operational procedures,

Order 500, which eliminated the requirement for FERC confinement, and geological and engineering properties. This

approval as to the financial “soundness” of a construction should include all native gas (recoverable and unrecoverable),

project if the pipeline company were willing to accept the cushion (base) gas, and working (current) gas.

market rate of return for the project.

Peak or Peak Load: The maximum demand for gas on a the supplier or local distribution company to the ultimate end

system during a specified interval: hour, week, month, or user. System gas is subject to FERC or State tariff and is

year. generally sold under long-term (contract) conditions.

Peak Shaving: Injection of supplemental supplies of Throughput: Actual or estimated volume of natural gas that

natural gas, such as from underground storage or liquefied may be carried on a pipeline over a specified period of time.

natural gas (LNG) facilities, into the pipeline system during

periods of maximum demand. Also applies to the act of Total Storage Capacity: The sum of working (current) gas

installing such facilities as a way of avoiding expanding (or capacity and the cushion (base) gas that must remain in the

building) the production-to-market capacity of the system storage reservoir for purposes of pressure maintenance.

to accommodate fully the potential maximum demand loads

on the basic system. Trunkline (Transmission) System: Long-distance, wide-

 diameter pipeline system that generally links a major supply

Pipeline Sales Service: Before 1992, interstate pipeline source with a major market area or with a major pipeline/LDC

companies provided bundled sales and transportation serving a market area. Trunklines tend to have only a few

service at regulated rates. This bundled service was receipt points (usually at the beginning of its route), few

discontinued in 1993, for most customers, by Order 636, delivery points or interconnections with other pipelines, and

which allowed pipeline companies to sell unbundled gas at few, if any, associated lateral lines. Also see mainline.

market-based rates. Order 636-A required pipeline

companies to continue bundled sales service to their Upstream Pipeline: A pipeline, or portion thereof, which is

existing small customers at cost-based rates for a closer to the production area or primary receipt point for gas

transitional 1-year period. supplies.

Psia: Pounds per square inch at atmospheric pressure. Utilization Rate: Daily flow (throughput) as a percent of

Service Agreement: An agreement between a natural gas utilization rate equals the average-day flow divided by the

company and a gas purchaser or shipper specifying the estimated capacity.

service to be rendered, area to be served, maximum

obligation to deliver, delivery points, delivery pressure, Working (Current) Gas: The volume of gas in an

applicable rate schedules by reference to the tariff, effective underground storage reservoir in excess of total cushion (base)

date and term, and identification of any prior agreements gas and which is available for delivery (withdrawal).

being superseded.

contracts as long as 1 to 2 years are sometimes categorized as

Storage (Reservoir) Operating Capacity: The maximum

System Supply: Gas supplies purchased, owned, and sold by

estimated capacity. For a segment of pipe, the average-day